ML20140C593

Insp Rept 50-271/97-02 on 970119-0308.Violations Noted. Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML20140C593
Person / Time
Site:	Vermont Yankee
Issue date:	04/09/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20140C585	List: ML20140C581 ML20140C587 ML20140C593
References
50-271-97-02, 50-271-97-2, NUDOCS 9704170152
Download: ML20140C593 (26)

See also: IR 05000271/1997002

Text

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. ENCLOSURE 2

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U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket No. 50-271

Licensee No. DPR-28

Report No. 97-02

Licensee: Vermont Yankee Nuclear Power Corporation

Facility: Vermont Yankee NucNar Power Station

Location: Vernon, Vermont

l Dates: January 19 - March 8,1997

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inspectors: William A. Cook, Senior Resident inspector <

Edward C. Knutson, Resident inspector

Laurie A. Peluso, Radiation Physicist, Region I

Thomas Koshy, Sr., Reactor Systems Engineer, NRR

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Approved by

Richard J. Conte, Chief, Projects Branch 5  !

Division of Reactor Projects

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EXECUTIVE SUMMARY

Vermont Yankee Nuclear Power Station

NRC Inspection Report 50-271/97-02

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This integrated inspection included aspects of licensee operations, engineering,

maintenance, and plant support. The report covers a 7-week period of resident inspection.

In addition, it includes the results of an announced inspection by an Office of Nuclear

Reactor Regulation (NRR) inspector and a regional specialist inspector input.

Operations

The inspector concluded that the VY staff responded appropriately to the initial

identification of the reactor core isolation cooling system lubricating oil drain line broken

hanger and took prompt action to correct the deficiency. The subsequent assessment of no

impact on system operability was adequately founded and the 10 CFR 50.72 notification

retraction was proper.

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The licensee took prompt action to revise the RHR system operating procedure (OP-2124) {

to administratively eliminate use of this alternate keep-fill method following their l

determination that no primary containment isolation feature exists for this piping l

configuration. l

The inspector considered the licensee's initial response to the turbine building HELB

concern, including operability determination and compensatory measures, to be thorough

and timely. The inspector will monitor and assess final resolution of this issue in a i

subsequent inspection period (IFl 97-02-03).

Maintenance l

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The inspectors observed, on February 24-26, portions of the "A" reactor feedwater pump

overhaul activities. No problems or concerns with the conduct of these maintenance

activities were observed by the inspector. i

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The inspector concluded that personnel performance during the conduct of the quarterly

standby fuel pool cooling system test was good. The licensee's planning and coordination

with all responsible departments was proved effective. The material condition of the spent I

fuel cooling system was good. The Quality Assurance auditor's inspection technique was l

appropriate and unobtrusive. Overall, good procedure adherence was observed.

The licensee appropriately concluded that the "B" main station battery was operable, but  ;

degraded, upon discovery of the loose intercell connection during surveillance testing on

April 15,1995. The preservation and assessment of as-found conditions could have been

better, but licensee staff performance in this area has been enhanced since this event,

based upon the promulgation of lessons learned.

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The Operations department root cause evaluation for the November 25,1996 electrical bus

l No. 6 on-line de-energization event was adequately self-critical and identified the principal

causal factors for the event. The inspector concluded that the root cause of the event was

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a failure to follow AP-0125, Appendix B and cited this procedural non-compliance as a

violation of regulatory requirements (VIO 97-02-04). Also, the inspector concluded, as did ,

?- the licensee, that a weakness in the work planning process significantly contributed to this

evolution not being reviewed more thoroughly, in advance.

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Per the original inspector concern raised in inspection report 94-16, the licensee completed

an appropriate representative sample of harsh environment susceptible instrument loop error

, calculations and confirmed that, althcugh some instrument TS allowable values may be

exceeded, the " analytical limits" did not compromise the bounding LOCA safety analyses.

! Accordingly, URI 94-16-02 is closed. However, the licensee's application of

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ISA-S67.04-1987 and basis for concluding that the instrument loop derived " analytical

limit" may exceed the TS allowable value remain unresolved. This unresolved item, along

j with the NRC staff g review of the instrument Setpoint Program results, wi!! be examined in

a future inspect;on (URI 97-02-09).

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Enaineerino

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j The licensee has adequately addressed the issue regarding the absence of heaters for the

l motors of the HPCI and RCIC systems. The licensee's routine preventive maintenance

program and the timeliness of any needed corrective maintenance provide reasonable

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j assurance of continued operability of these components.

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The NRR inspector concluded that there was no immediate safety concern involving the~

,- mixing of electrical neutrals and ground wires on this issue since only a narrow range of

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electrical fault protection is potentially degraded. An Unresolved item (URI 97 02-05) will

track future NRC reviews of VY staff actions to ensure resolution of any further electrical

separation issues involving the AOG system, including an evaluation of the cause for this *

problem and an assessment of the adequacy of corrective actions. The performance history

of the AOG system demonstrates the system's capability to comply with the applicable NRC

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and state effluent release regulations.

A number of plant design issues were identified during this inspection period requiring

additional licensee action and inspector follow-up/ verification of corrective action adequacy.

, inspection follow items have been assigned to these issues, as annotated in the report,

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Plant Sucoort

i Radiation worker and radiation protection staff performance associated with the free

releasing of the Framatome bridge assembly was generally good, but some inattention with

respect to the monitoring of the clean area boundary was noted.

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! On February 12, the licensee performed a practice emergency plan exercise for training

purposes. The practice exercise involved participation by the local offsite emergency

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response organizations. The inspector observed the licensee's activities from the Technical

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.- Support Center (TSC) and the Operations Support Center (OSC). The TSC and OSC.were

staffed immediately after the declaration of the " Alert" emergency classification. Good

communication was observed between the OSC, TSC, and Simulator Control Room. The

inspector noted no performance concerns or emergency plan implementing problems.

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TABLE OF CONTENTS

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

TA B L E O F C O N TE NTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

S u m m a ry o f Pla nt Statu s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1. Operations ................................................. 1

01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

01.1 Reactor Core isolation Cooling System Operability Concern ..... 1

01.2 Primary Containment isolation System Design Vulnerability ..... 1

01.3 Low Pressure Coolant injection (LPCI) Operability Concern . . . . . . 2

01.4 High Energy Line Break (HELB) Analysis Error ............... 2

II. M a in t e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

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M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

M 1.1 Maintenance Observations ............................ 3

M 1.2 Surveil'ance Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

M8.1 Licensee Event Report Review, IFl 96-09-04 (Closed) ......... 4

MS.2 (Closed) URI 95-06-01: Review of "B" Main Station Battery

Operability Determination ............................. 5

M8.3 (Closed) IFl 96-10-01: Performance of On-Line Electrical Bus

Preventive Maintenance .............................. 6

M8.4 (Closed) URI 94-16-02: Adequacy of Instrument Loop Accuracy . 8

lli. Eng in e e ri ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........... 9

El Conduct of Engineering ................................... 0

E1.1 Emergency Core Cooling System . . . . . . . . . . . . . . . . . . . . . . . . 9

E1.2 Plant and Electrical Power System . . . . . . . . . . . . . . . . . . . . . . . 11

E7 Quality Assurance in Engineering Activities ..................... 13

E7.1 Design Basis Documentation / Technical Specification

Improvement Projects issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

IV. Plant Support ............................................... 14

R4 Staff Knowledge and Performance in RP&C ..................... 14

P4 Staff Knowledge and Performance in EP . . . . . . . . . . . . . . . . . . . . . . . . 15

P4.1 Licensee Practice of Emergency Plan Exercise . . . . . . . . . . . . . . . 15

F8 Miscellaneous Fire Protection issues .......................... 15

F8.1 (Update) URI 96-08-01: Switchgear Room Carbon Dioxide

Suppression System Corrective Actions Review ............. 15

V. Ma nagem e nt Meeting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

X1 Exit M eeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

X3 Management Meeting Summary ...................... .... . 15

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X5 Review of Updated Finals Safety Analysis Report (UFSAR) . . . . . . . . . . 16 i

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l INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 i

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ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18  ;

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PARTIAL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . . . 19

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LIST OF ACRONYMS USED ..... ................................... 20

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DETAILS

Summarv of Plant Status

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Vermont Yankee (VY) operated at 100 percent reactor power throughout this inspection

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period with the exception of power reductions to conduct planned rod patterns exchanges 1

and surveillance testing. The licensee conducted a practice emergency plan exercise for '

trainir'g on February 12 which included participation by local off-site emergency response i

organizations. On January 30,1997, the NRC staff conducted the Systematic Assessment

of Licensee Performance (SALP) board in the Region I office in King of Prussia, PA. The .

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results of the SALP were documented by letter and enclosed report dated March 5,1997.

The SALP management meeting conducted by the Region 1 Regional Administrator and VY

senior managers was held on March 12,1997 at the Vernon, VT Town Hall. l

1. Operations

01 Conduct of Operations'  ;

01.1 Reactor Core isolation Cooling System Operability Concern i

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On January 27,1997 the VY staff notified the NRC (Event No. 31663)in accordance with l

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10 CFR 50.72, that an engineering staff walkdown of the reactor core isolation cooling

(RCIC) system identified a broken pipe hanger on the RCIC pump lubricating oil casing drain  !

line. The broken hanger is located downstream of the drain line safety class-2 isolation

valve and therefore not a part of the RCIC system pressure boundary. However the hanger

is a seismic support that could affect the RCIC system pressure boundary if not functional.

Accordingly, the licensee declared the RCIC system inoperable, entered the 7-day Technical

Specification (TS) limiting condition for operation (LCO), and initiated a work order to repair

the hanger.

Subsequent engineering evaluation concluded that the broken hanger did not adversely I

impact RCIC system operability. VY concluded that the drain line was adequately supported

such that it would have maintained its integrity through a seismic event in the as-found I

condition (reference YAEC memorandum, dated February 7,1997). On February 25,1997,

l VY retracted their January 27 notification based upon the findings of the engineering  !

evaluation. The inspector concluded that the VY staff responded appropriately to the initial  !

identification of the broken hanger and took prompt action to correct the deficiency. The

subsequent assessment of no impact on system operability was adequately founded and the

10 CFR 50.72 notification retraction was proper.

01.2 Primary Containment Isolation System Design Vulnerability

On February 6,1997 the VY staff notified the NRC (Event No. 31744) in accordance with

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10 CFR 50.72, that during a causal analysis investigation for an unrelated issue the VY

staff identified that a postulated single electrical failure could affect primary containment

integrity. Specifically, a single failure of the torus /drywell vent and purge valve control

' 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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circuitry while containment inerting/de-inerting was in progress, concurrent with a loss of

coolant accident (LOCA), could result in a flow path for steam to bypass suppression

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chamber submergence cooling and potentially cause the over-pressurization of primary

j containment. The VY staff documented their preliminary assessment of this event via

Licensee Event Report (LER) No. 97-01, dated February 27,1997. The inspectors plan to

review this report and assess the adequacy of the licensee's corrective action in a

l subsequent inspection (IFl 97-02-01).

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01.3 Low Pressure Coolant injection (LPCI) Operability Concern l

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On March 6,1997, the VY staff notified the NRC (Event No. 31906) in accordance with l

10 CFR 50.72, that the accident mitigation capability of the LPCI system could be 5

compromised by a procedurally approved alternate discharge piping keep-fill line-up for the l

! residual heat removal (RHR) system. The alternate keep-fill method employs a 4-inch j

, condensate transfer system pipe connection with no reverse flow check valve or automatic i

containment isolation capability. Accordingly, if the alternate keep-fill method were in- l

l service and the LPCI system were called upon to function for accident mitigation, this pipe i

connection could result in a significant diversion of injection flow. l

The licensee took prompt action to revise the RHR system operating procedure (OP-2124)

! to administratively eliminate use of this alternate keep-fill method. The inspector plans to

! review the licensee's evaluation of this event and additional corrective actions following j

issuance of their LER (lFI 97 02-02).  !

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01.4 High Energy Line Break (HELB) Analysis Error

On March 7,1996, the VY staff notified the NRC (Event No. 31915) in accordance with ~

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10 CFR 50.72, that a review of the turbine building HELB analysis identified that the I

assumption of 1,000 square feet of pressure relief capacity at 0.25 psig was invalid. A -

walkdown of the turbine building concluded that no designated pressure relieving dampers  !

were installed. Although some ventilation dampers could be credited for pressure relief, l

, these dampers provided only a fraction of the assumed relief capacity. Preliminary

, engineering design calculations demonstrated that the turbine building walls would fail at  !

approximately 1.4 psig. However, prior to reaching 1.4 psig, three adjacent block walls

may exceed their design pressure retaining capacity and potentially fail before the turbine

building walls. The postulated failure of these block walls jeopardized the functionality of j

the two emergency diesel generators (EDGs) and their respective fuel oil day tanks; the

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electrical switchgear room components; and the heating, ventilation and cooling (HVAC)

systems of the control building.

The inspector observed the licensee's discussions and reviewed the preliminary operability

determinations for the affected areas and safety systems. Engineering evaluations

concluded that the EDG and EDG day tank block walls would withstand the maximum

turbine building pressere of 1.4 psig because the block wall design limit of 1 psig had

sufficient margin to the projected failure of the block wall (pressures of between 2.0 and

2.5 psig). The exposed switchgear room block wall could be protected by a compensatory

measure which involved the closure of a fire door at the entry to the corridor from the

turbine building to the radwaste building. The licensee could not immediately show

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protection of the HVAC room block wall and thus declared it non-functional for a turbine

building HELB. This condition resulted in the previously credited mild environment of the

HVAC room being a harsh environment for equipment environmental qualific ' tion (EO)

purposes. The immediate impact of this EQ concern was that the control room HVAC

system could be compromised. Compensatory measures were promptly identified and

promulgated via Night Orders to ensure the control staff could effectively respond to this

type of event.

The inspector considered the licensee's initial response to this HELB concern, including

operability determination and compensatory measures, to be thorough and timely. The

inspector will monitor and assess final resolution of this issue in a subsequent inspection

period (IFl 97-02-03).

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II. Maintenance

M1 Conduct of Maintenance

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M1.1 Maintenance Observations

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a. Inspection Scope (62707)

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 ensure personnel safety

and prevent damage to plant structures, systems, and components, and to ensure that

equipment operability was verified upon completion of post maintenance testing.

b. Observations, Findinas, and Conclusions

The inspectors observed, on February 24-26, portions of the "A" reactor feedwater pump

overhaul activities. No problems or concerns with the conduct of these maintenance

l activities were observed by the inspector.

M1.2 Surveillance Observations

a. Inspection Scope (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,

b. Observations and Findinas.

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The inspectors observed all or portions of the following surveillance tests:

• "A" and "B" emergency diesel generators monthly surveillance testing. No concerns

or problems were identified.

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• .OP 4179, " Standby Fuel Pool Cooling Quarterly Surveillance"

On February 13, the VY staff performed the standby fuel pool cooling system

quarterly surveillance test as required by TS 4.6.E.2. The test was performed per

the schedule and included radiation protection and maintenance staff support. All

responsible persons involved in the surveillance, including the quality assurance (QA)

auditor, attended the pre-job briefing conducted by the operations staff. The briefing

included a discussion of the surveillance, worker expectation, and provided adequate

time for workers to ask questions or present suggestiorts relative to the conduct of

the test. The inspector observed that all groups were well prepared with the correct

test instruments, tools, and equipment needed to perform the job task efficiently and

correctly. The test instruments used were properly calibrated.

Prior to entering the radiologically controlled area (RCA) to perform the test, all

workers read, understood, and signed-in on the appropriate radiation work permit

(RWP). Radiation protection (RP) technicians ensured good radiation worker

practices were observed. Proper radiation dose rate and contarnination swipe

surveys were conducted. The responsible auxiliary operators (AOs) closely followed

the test procedure. The QA auditor's observation of this surveillance test was part

of a broader evaluation of the Operations department staff performance. The

inspector observed that the QA auditor had prepared in advance and asked probing

questions of the workers and operators to assess their knowledge of the system and

the testing requirements. The inspector noted that the auditor did not provide

assistance to the workers or impede the workers' performance during the test. The

auditor observed and collected data independent from the workers,

c. Conclusions

Based on the above observations and interviews, the inspector concluded that personnel

perforraance was good. The licensee's planning and coordination with all responsible

departments was proven to have been effective. The material condition of the spent fuel

cooling system was good. The Quality Assurance auditor's inspection technique was

appropriate and unobtrusive. Overall, good procedure adherence was observed.

M8 Miscellaneous Maintenance issues

M8.1 Licensee Event Report Review, IFl 96-09-04 (Closed)

a. Insoection Scoce (92700)

Using the guidance of Inspection Procedure 92700, the inspectors reviewed the Licensee

Event Report (LER) discussed below to verify the VY staff had implemented the corrective

actions, as stated in the LER, and to determine whether their response was appropriate and

met regulatory requirements.

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b. Observations and Findinas

LER 96-031, " Alternate rod insertion / recirculation pump trip (ARl/RPT) due to inadvertent

false low water level signal on a level transmitter during backfill of a reference leg," dated

January 29,1997.

This event occurred during the 1996 refueling outage and was discussed in inspection l

report 96-09. The item was tracked as an inspector followup item, IFl 96-09-04, pending i

review of the licensee's event report submittal. As discussed in inspection report 96-10,

the licensee determined that, in accordance with guidance concerning the reportability of

ESF actuations in NUREG 1022, " Event Reporting Guidelines 10 CFR 50.72 and 50.73," the

event was not reportable. The in roector disagreed with this conclusion and considered that

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different criteria in NUREG 1022 made the event reportable. '

The licensee subsequently determined that the event was not reportable because it was not

an ESF actuation. The ARl/RPT is the protective action that is initiated by the anticipated l

transient without scram (ATWS) mitigation system; this system is not considered an ESF at l

Vermont Yankee. However, NUREG 1022 acknowledges that ESFs are not the same at all

plants, and requests that actuations of specified systems (one being the ATWS mitigation  !

system) be reported, on a voluntary basis if need be. Accordingly, the licensee submitted

LER 96-031 as a voluntary LER. I

The licensee determined that the root cause of the ARl/RPT actuation was personnel error,

in that the technician performing the work did not review the installation instructions in

sufficient detail. A contributing cause was determined to be insufficient detail in the work

order. Long term corrective action to evaluate the detector reference leg backfill process

and develop a method to identify all detectors that would be affected by any specific

backfill operation is expected to be complete by June 1997.

c. Conclusions

The inspector considered that the licensee's corrective actions appropriately addressed the

causes of the event. The ARl/RPT was not safety significant and did not affect plant

operations, because the reactor was shut down with the vessel head removed and the

cavity flooded for refueling. Accordingly, LER 96-031 and IFl 96-09-04 are closed.

M8.2 (C!osed) URI 95-06-01: Review of "B" Main Station Battery Operability

Determination

a. Backaround and Insoection Scoce (61726)

During an April 15,1995, TS required load profile surveillance test of the "B" main station

battery, a low cell voltage condition was identified. The test was appropriately placed on

hold and the intercell connection between cells 10 and 11 were found to be only finger

tight. The bolted connection was torqued to the proper value and the load profile test

completed satisfactorily. Based upon the discovery of this degraded condition, VY made a

notification per 10 CFR 50.72(b)(2)(i) on April 15,1995, and stated that the "B" battery

would have been unable to provide the current specified in the first minute of the load

profile.

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On April 24,1995, VY retracted this 10 CFR 50.72 notification based upon an evaluation

that concluded the "B" battery would have been able to perform all required functions and

therefore was operable since the previous load profile test (October 1993), and as

demonstrated by more frequent periodic checks. An unresolved item was assigned to this i

event to review the licensee's completed operability determination and to examine the

licensee's efforts to improve their performance in the area of preservation of "as-tound"  ;

conditions for subsequent root cause investigation and system / component operability )

assessments. l

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b. Observations and Findinas  !

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The inspector reviewed the licence's operability determination and cons;dered it )

acceptable. In the absence of a definitive resistance check of the finger tight intercell {

bolted connection, a precise cell voltage output could not be determined. However, the i

main station batteries are sized to provide sufficient voltage margin with only 59 of the

60 cells operable (reference inspection report 96-09, section M3.4). Consequently, on

April 15,1995, the "B" battery should have had adequate margin with the as-found

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degraded intercell condition to perform its intended safety function.

With respect to the concern involving licensee staff preservation of the as-found conditions,

VY acknowledges that resistivity readings on the affected battery cell could have provided

additional information to support the operability determination of the "B" battery. This was

a lessons learned for the event and was promulgated to the maintenance staff via de-

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partment meetings and classroom training sessions. Since this event in April 1995, the

inspectors have witnessed an increased sensitivity on the part of the VY staff to preserve

as-found degraded component conditions. For example, the "A" EDG output breaker found

, inoperable on September 13,1996, (reference inspection reports 96-09, section 01.2 and

. 96-11, section M8.1) was immediately quarantined to preserve the as-found conditions to

facilitate a detailed component failure analysis.

c. Conclusions

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The licensee appropriately concluded that the "B" main station battery was ope able, but

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degraded, upon discovery of the loose intercell connection during surveillance tssting on

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April 15,1995. The preservation and assessment of as-found conditions could have been

better, but licensee staff performance in this area has been enhanced since this avent based

i upon the promulgation of lessons learned.

M8.3 (Closed) IFl 96-10-01: Performance of On-Line Electrical Bus Preventive Maintenance

a. Backaround and Inspection Scone

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As previously dircussed in inspection report 96-10, section M1.2, the VY staff de-energized

non-safety related 480V electrical bus No. 6 on November 25,1996, for planned preventive

maintenance. As a consequence, the condensate demineralizer bypass valve opened and

the demineralizer inlet valves closed, unexpectedly. The licensee initiated an Event Report

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(ER 96-1131) and assigned a root cause assessment to be conducted by the Operations

department for this event. The inspectors conducted a review of the root cause evaluation

completed by the Operations department and assessed the adequacy of the corrective

actions taken or planned.

b. Observations and Findinas

By memorandum dated March 2,1997, the Operations department completed their root

cause evaluation for ER 96-1131. The evaluation concluded there were two root causes

and three contributing causes. The root causes were: 1) lack of sufficiently detailed and

controlled policy for conduct of on-line bus de-energization; and 2) insufficient review of

loads for the specific bus de-energization evolution to be performed. The three contributing

causes were: 1) operations personnel not aware of Appendix A and 8 of Administrative

Procedure (AP)-0125, " Plant Equipment Control," and the shift supervisor operating to

Standing Order No.16 only; 2) lack of formal consideration given to operational concerns in

the work planning process; and,3) lack of crew briefing for the Bus 6 de-energization. '

Based upon these causes, the VY staff proposed that the governing administrative

procedures (AP-0125 and AP-0048, " Work Planning") be revised to provide more specific

guidance and clarity for the conduct of on-line electrical bus or power supply de-

energization work. In addition, the licensee proposed to revise and then cancel Standing

Order No.16, pending the revision to AP-0125, and review the lessons learned of this

event via the operator training program.

The inspector considered this root cause evaluation and related corrective actions overall

adequate, with one exception. The inspector agreed that the existing procedural guidance

for the control of plant equipment (AP-0125 and Standing Order No.16 " Administrative

Controls on Bus De-energitation") and work planning (per procedure AP-0048) could be

improved. However, the inspector observed that AP-0125, Appendix B, " Conditions

Required to Remov6 Non-Technical Specification Required Equipment From Service,"

revision 7, provided sufficient guidance and clarity, but was not followed (reference licensee

contributing cause #1). The inspector noted that AP-0125, Appendix B states, in part, that

prior to planned evolutions which will remove from service any power supply (i.e., bus,

motor control center, power panel) the shift supervisor will ensure a detailed review of loads

impacted by the de-energization of the power supply is completed. The licensee's

evaluation of this event did not conclude that AP-0125 was not adhered to. Accordingly,

the shift supervisor's individual failure, as well as, the plant staff's collective failure to )

invoke and adhere to the requirements of AP-0125, Appendix B,is a violation of Technical 1

Specification 6.5. (VIO 97-02-04). l

!

The inspector acknowledges that the shift supervisor and operating crew responsible for

releasing the No. 6 electrical bus for preventive maintenance was the last line of defense

which failed and led to this event. The licensee's root cause evaluation identified that AP-

0048, " Work Planning" does not consider plant operational concerns as a formal part of the

work planning and preparation process. The inspector similarly viewed this as a work

control weakness and significant contributing cause for the event, particularly, due to the

f act that this was the first time Bus No. 6 was de-energized for preventive maintenance

while the plant was in operation.

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' As discussed in the licensee's root cause evaluation, Standing Order No.16 was out-dated

in comparison to the Appendices of AP-0125. Follow-up discussions with the Operations

Department Manager identified that, in eddition to the prompt revision of Standing Order

No.16 to address immediate corrective actions for this event, all Operations department

Standing Orders would be examined to ensure they were not out-of-date or in conflict with

station administrative procedures. Corrective actions to prevent a recurrence would also be

considered by the licensee.

)

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, C. Conclusions

The Operations department root cause evaluation for the November 25,1996, electrical Bus

,

No. 6 on-line de-energization event was adequately self-critical and identified the principal

causal factors for the event. The inspector concluded that the root cause of the event was l

a failure to follow AP-0125, Appendix B and cited this procedural non-compliance as a

violation of Technical Specification 6.5 (VIO 97-02-04). Also, the inspector concluded, as <

did the licensee, that a weakness in the work planning process significantly contributed to  !

this evolution not being reviewed more thoroughly, in advance. I

i

, M8.4 (Closed) URI 94-16-02: Adequacy of instrument Loop Accuracy

a. Backaround and insoection Scooe (61726)

.

During an earlier inspection, the review of selected instrument trip settings identified that

the instrument loop error under certain LOCA or HELB accident conditions may result in the

UFSAR and TS trip level setting (allowable value) for a specific instrument being exceeded.

'

A specific example involving reactor vessel pressure transmitters was identified as

potentially exceeding the TS maximum pressure trip setting. The inspector notes that the

allowable value accounts for the trip setpoint plus any associated process instrument

uncertainties. As a consequence, the licensee conducted a detailed review of similar TS <

'

instrument loops to verify established TS trip level settings were maintained and to ensure

safety limits were not challenged.

Using the guidance of Inspection Procedures 61726 and 92702, the inspector examined the

licensee's resolution of the unresolved issue discussed above,

b. Observations and Findings

in response to the inspector's observations documented in inspection report 94-16, dated

August 11,1994, the licensee completed a review of 32 environmenta!Iy qualified (EG)

instrument loop error calculations, as documented in Yankee Atomic Energy Corporation

(YAEC) memorandum, dated November 24,1994. This review concluded that during

normal environmental conditions, all TS allowable values would be satisfied. However, for

seven of the selected instruments, harsh environmental conditions could potentially result in

the instrument protective function (trip setpoint) occurring outside the TS allowable value.

The inspector determined that for those cases where the " analytical limit" may possibly

exceed the TS allowable value, an engineering evaluation was performed. These

evaluations examined the bounding cenditions of the LOCA analyses and confirmed that the

established safety limits would not be compromised. For example, (reference YNSD memo,

. 9

dated March 24,1997) emergency core cooling system (ECCS) initiation and isolation

signals (TS limit) from reactor pressore vessel level instrumentation are .;>_82.5" and

.1177", respectively. The nominal setpoints are 87" and 175", but the HELB analytical trip

setpoints are 81.5" and 179", respectively. The licensee concludes that these HELB

analytical trip values are not consequential because the bounding analysis is the LOCA

analysis for which the analytical trip setpoints are 82.5" and 175", respectively.

The inspector noted that YAEC references instrument Society of America Standard

ISA-S67.04-1987, "Setpoints for Nuclear Safety-Related Instrumentations," as a basis for

the acceptability for the approach of allowing the harsh environment established " analytical

limit" to exceed the TS normal environmental (operating) condition established limit. In

addition, YAEC maintained that the established TS normal environmental condition allowable

values and instrument loop errors were per the current licensing basis.

The inspector determined that following the licensee's November 24,1994 conclusions,

additional reviews were conducted as documented in YAEC memorandums dated April 19,

1995; May 11,1995; and June 27,1995. The June 27,1995 memorandum concluded

that no revisions to the TS or the UFSAR were needed based upon the analysis completed,

to date. However, YAEC recommended that VY " reconsider implementation of an

[ instrument) setpoint control program to ensure the uncertainty calculations reflect as-built

conditions." As announced by licensee management in mid-1996, VY embarked upon a

conversion to improved Technical Specifications (ITS). In conjunction with the ITS program,

VY is conducting a design basis documentation effort and a detailed instrument setpoint

program (ISP) to support the ITS project.

c. Conclusions

Per the original inspector concern raised in inspection report 94-16, the licencee completed

an appropriate representative sample of harsh environment susceptible instrument loop error

calculations and confirmed that, although some instrument TS allowable values may be

exceeded, the " analytical limits" did not cornpromise the bounding LOCA safety analyses.

Accordingly, URI 94-16-02 is closed. However, the licensee's application of

ISA-S67.04-1987 and basis for concluding that the instrument loop derived " analytical

limit" may exceed the TS allowable value remain unresolved. This unresolved item, along

with the NRC staff's review of the Instrument Setpoint Program results, will be examined in

a future inspection (URI 97-02-09).

111. Engineering

E1 Conduct of Engineering

E1.1 Emergency Core Cooling System

a. Inspection Scope (37700)

A representative of the Office of Nuclear Reactor Regu!ations (NRR) reviewed the licensee's

action to disconnect the motor heater circuits for the high pressure coolant injection (HPCI)

system and reactor core isolation cooling (RCIC) system motors, which were part of the

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original design. The inspection was to review the prudence of this modification and to  ;

assess if all design bases environments were addressed.

b. Observations and Findinas I

in 1988, the licensee took action to disconnect the motor heaters in response to

observation made during the troubleshooting of the failure of the HPCI gland seal exhaust

motor. The licensee noticed that the insulation was excessively dry and the wire close to

the heater broke due to high temperature and slight rubbing.

The motors in the HPCI and RCIC systems are part of the original design equipped with

heaters for the motor. These motors are not a customized design for nuclear application,

but were found to meet the specific duty requirement for the subject systems. In typical

ir dustry application, these motors are not housed in closed rooms with HVAC systems, and

not generally situated close to electric power distribution centers. Consequently, the

motors are equipped with heaters that will provide the required heat to keep it above

ambient temperature and prevent condensation at remote locations. If these motors are

used in rooms with HVAC systems and the power distribution is close to rated voltage

(because of close proximity to the power distribution center) the heater output could cause

insulation dry out.

This issue was previously addressed by the NRC in inspection reports 96-06, section E2.1

and 96-09, section E2.1. These inspections reviewed the licensee's actions in response to

a VY staff engineer's differing professional opinion for disconnecting the space heaters.

The inspector concluded that the licensee adequately addressed the issue, and that the

licensee's action to keep the heaters disconnected was appropriate.

During this inspection, the NRR inspector conducted an independent evaluation to verify if

the motor locations could be exposed to conditions requiring heaters. Both HPCI and RCIC

. rooms that house the subject motors have other sensitive electrical components such as

relays, pressure indicators on electrical panels, and motor control centers. The inspector

looked for potential signs of condensation, such as water marks and rust, in these

components and no indications were found. The inspector also selected a sample of such

sensitive instruments and reviewed the maintenance history to look for component f ailures.

No examples were found that could be attribJted to condensation damage.

In June 1996, the licensee conducted temperature and humidity measurements inside of

HPCI and RCIC rooms and outside, including periods when cooling towers were in

operation. Even though this period may not be the worst case for humid environment, it

reflects close to worst conditions. The humidity in these rooms remained in the mid-fifties

and stayed below 63 percent during the monitored period. The inside temperature remained

above 80 F while the outside temperature dropped to 65 F.

Both the HPCI and RCIC system rooms are at the lowest elevation of the reactor building

and each have a large opening to the torus area that is open to higher elevations. These

rooms remain at a higher temperature because of a 10-inch steam line running for

approximately 50 feet in the HPCI room and a 3-inch steam line which runs for

approximately 30 feet in the RCIC room. These steam lines act as heat sources and keep

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the rooms warmer whenever the plant is at power. (Reactor steam production is needed for

these systems to operate). If condensation was to occur, it should be away from these

rooms where the temperature is relatively lower.

Additionally, the licenseo's preventive maintenance program includes the measuring of the

insulation resistance for these affected motors. These measurements should provide an

early detection of any insulation degradation. The ter,t results and motor performance in the

last seven years, after the space heaters were disconnected, have been acceptable. The

motors that were part of the original plant equipment continued to function, as

demonstrated in the surveillance tests, in its required service.

The primary safety function of the HPCI and RCIC systems is to mitigate a small break

LOCA while the reactor coolant system pressure remains above the capability of low

pressure safety injection systems. The HPCI and RCIC rooms should remain unchallenged

during a design bases small break LOCA and therefore, these systems should be able to

perform their prescribed safety function. In case of a large break LOCA, these systems are

not credited and their contribution is insignificant in relation to the large volume low

pressure safety systems required for accident mitigation.

in case of a HELB inside the reactor building, the credited systems are automatic

depressurization, and "A" and "B" containment spray. More specifically, the HPCI and

RCIC system motors are not relied on as the primary emergency core cooling systems when

they are susceptible to degradation from the accident environment. Additionally, the

demand for HPCI and RCIC is just after the accident and therefore the system should begin

its function before any potential condensation could reach motor windings. This delay in

environmental challenge to these motors would further reduce the possibility for {

condensation because of the motor heat-up from its operation. This is in agreement with j

the licensee's classification of these motors for equipment qualification.  !

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The NRR inspector concurred with the prior regional assessment documented in inspection  !

reports 96-09 and 96-06 that the motor heaters were not required for the HPCI and RCIC

systems to perform their safety function.

c. Conclusions

The licensee has adequately addressed the issue regarding the absence of heaters for the

motors of the HPCI and RCIC systems. The licensee's routine preventive maintenance

program and the timeliness of any needed corrective maintenance provide reasonable

assurance of continued operability of these components.

E1.2 Plant and Electrical Power System

a. Insoection Scoce (37700)

The NRR inspector reviewed the advanced off gas (AOG) system and its associated

electrical power, control, and instrumentation power supplies to verify that electrical

protection and signal separation was in compliance with the Updated Final Safety Analysis

Report (UFSAR) commitments.

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b. Observation and Findinas

The inspector examined drawing revisions that addressed the failure to follow wiring

practices that could degrade the performance of circuit protective devices to promptly

isolate electrical faults.

The VY AOG system design is unique to the nuclear industry. The system was designed

through a contractor. During design improvement reviews performed between 1994 and i

1995, the plant staff noticed that the panel wiring did not agree with the drawings. In a i

May 1995 memorandum, the licensee documented the completion of as-built drawing l

reviews and the return of system wiring to sound electrical wiring practices. The licensee )

'

identified four wiring errors in control room panel 9-50, where the neutral of the plant's

instrument AC system was used as an electrical return path for the AOG system power

sources,

in an October 8,1996 memorandum, VY requested a re-review of the grounding and neutral i

connections in response to additional questions raised in this area and an event at the

Palo Verde Nuclear Power Station involving a short circuit causing smoke in two fire zones.

From this review and as documented by memorandum dated January 8,1997, one more

wiring deficiency involving crossing the neutral connection was found, along with other ,

minor drawing errors. This crossing error involved connecting a non-safety control circuit '

neutral to a different non safety AOG motor control center located in the same room.

The wiring errors identified were two kinds: (1) neutral side of power cables connected to

the instrument AC system, and (2) neutral of the control wire connected to the neutral of an i

adjacent motor control center. The first kind of error could cause electrical pulses to travel j

onto an instrument bus and cause interference to sensitive instrumentation. The first and 3

the second kind of errors degrade the fault isolation capability, if the neutral connection for J

the respective power source is not in the direct wiring, but through a different MCC or i

instrument bus and then through the plant ground to the respective MCC, the impedance in

the circuit is increased in proportion to the length of the wire. This added impedance would

reduce the fault current and could prevent or delay the protective device from clearing the

fault. The potential problem with the medium to high impedance faults, on the wires that i

run between field equipment and control room panels, is that they could remain uncleared. 1

The inspector determined that the low impedance type fault should not be a problem in the

deficiencies identified.

The UFSAR, Section 8.4.6.6, " Intermixing of Cables," revision 12, states that " low-level l

instrumentation cables are routed in separate trays from control cables." These low-level l

cables are defined as anything carrying less than 50 volts. The electrical connection of l

neutrals between instrumentation and control cables invalidates the intent of the FSAR

commitment in physical separation. The NRR inspector reviewed the plant trip history for

the last 3 years, and did not reveal any questionable association with AOG syctem  ;

problems. l

The licensee's focus on this electrical neutrals-to-ground mixing problem was limited to the

AOG system. A root cause evaluation of this concern was not done, but the licensee I

initiated an evaluation prior to the completion of the inspector's onsite visit. The NRR i

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inspector's review concluded that the primary cause was that the licensee's contractor

lacked knowledge in good wiring practices. . Good wiring practices are essential to circuit

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protection to prevent the spread of electrical faults. Based on the inspector's inquiry, the

licensee agreed to look into any of this contractor's work and later confirmed that the

contractor did not work on any other non-safety related or safety related systems. The

inspector also determined that the problems associated with the AOG system were not

tracked through the present problem resolution (Event Report) process. Accordingly, an

Unresolved item (URI 97-02-05) has been assigned to ensure NRC follow-up review of the

VY staff's action to conduct a root cause evaluation for these AOG system grounding

issues and to ensure mixed grounding is not a broader concern to other systems in the

plant. ,

c. Conclusion i

.

The NRR inspector concluded that there is no immediate safety concern on this issue since

only a narrow range cf electrical fault protection is potentially degraded. An Unresolved ,

item (URI 97 02-05) will track future NRC reviews of VY staff actions to ensure resolution

of any further electrical separation issues involving the AOG system, including an evaluation  :

of the cause for this problem and an assessment of the adequacy of corrective actions. The  ;

performance history of the AOG system demonstrates the system's capability to comply

with the applicable NRC and state effluent release regulations, t

E7 Ouality Assurance in Engineering Activities

E7.1 Design Basis Documentation / Technical Specification Improvement Projects issues

.

The licensee's Design Basis Documentation (DBD) and ITS projects have the potential for . f

identifying inconsistencies between the design, licensing, and operating bases of plant i

structures, systems, and components. Such inconsistencies will be documented in this

section of the report and tracked to resolution as inspection follow items.

During the inspection period, the licensee identified the following issues:

Event Report 97-177. Use of the main station batteries standbv charaer " CAB".

t

VY has two trains of emergency electrical power, Division I and Division 11. Each division

includes a 125VDC main station battery (A-1 and B-1) and a dedicated battery charger

(CA 1 and CB-1) which receives power from the AC portion of the division. A standby

battery charger, CAB, can be connected to either battery, in the event that the dedicated  !

charger fails or requires maintenance. Technical Specification 3.10.A.2.b allows the '

standby charger to be used indefinitely in place of either of the dedicated chargers.

-

However, the standby charger can only be powered from one source, motor control center

MCC-8B, which is a Division i electrical power source. If the standby charger was being

used in place of the Division 11 dedicated charger and a loss of Division i AC power ,

occurred, loss of both division DC systems would eventually occur due to inability to

recharge either of the batteries, in response to this finding, the licensee instituted

administrative controls to restrict the use of the standby charger with the Division 11 battery.  !

(IFl 97-02-06)

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Event Report 97-196. Adeauacy of off-site electrical oower system Technical Specification.

1

issues included investigating the equivaleacy of the immediate access power sources (the

auto transformer and the Keene line) and the delayed access power sources (backfeed I

through the main transformer and the Vernon tie line), and establishing appropriate LCOs. l

The licensee was preparing a basis for maintaining operability at the close of the inspection

period. (IFl 97-02-07)

Event Report 97-198. Station service water system / alternate coolina tower system

eauivalencv. l

TS 3.5.D.5 allows continued reactor operation with both station service water subsystems

inoperable for up to seven days, provided that the alternate cooling tower subsystem is

operable. The basis portion states, "The station service water subsystems and the alternate

cooling tower system provide alternate heat sinks to dissipate residual heat after a i

shutdown or accident." However, FSAR section 10.8 states, "The alternate cooling system j

is not classified as an Engineered Safeguard System and is not designed to accept the  ;

consequences of a design basis loss-of-coolant accident. It is also not single failure-proof."

The licensee has imposed more restrictive administrative requirements for operation with

degraded service water subsystems, pending further evaluation and possible TS l

amendment. (IFl 97-02-08) I

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IV. Plant Support {

R4 Staff Knowledge and Performance in RP&C

a. Insoection Scooe (71750)

The inspector observed radiological work control practices by the VY staff during their

efforts to free release portions of the refueling outage Framatome bridge assembly.

b. Observations and Findinas

The inspector observed various aspects of the plant staff surveying and decontaminating for

free release the last few sections of the Framatome bridge assembly used during the Fall

1996 outage. The licensee had designated an area of the Turbine Building truck bay, within

the RCA, as a " clean" area. The controls to enter and exit the area were good and the

licensee's frisking techniques were also good. However, the inspector noted a lack of close

attention to items on the boundary of this clean area. A chair, a rope, and an electrical cord

had crossed the physical control boundary, as well as, a table located adjacent to the

control boundary. These poorly monitored area boundary items were pointed out to the

radiation protection staff and appropriately resolved.

c. Conclusions

Radiation worker and radiation protection staff performance associated with the free

releasing of the Framatome bridge assembly was generally good, but some inattention with

respect to the monitoring of the clean area boundary was noted.

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P4 Staff Knowledge and Performance in EP

P4.1 Licensee Practice of Emergency Plan Exercise (82301)

On February 12, the licensee performed a practice emergency plan exercise for training

purposes. The practice exercise involved participation by the local offsite emergency

,

response organizations. The inspector observed the licensee's activities from the Technical

Support Center (TSC) and the Operations Support Center (OSC). The TSC and OSC were

, staffed immediately after the declaration of the " Alert" emergency classification. Good ,

i communication was observed between the OSC, TSC, and Simulator Control Room. The  !

,

inspector noted no performance concerns or emergency plan implementing problems.

F8 Miscellaneous Fire Protection issues

F8.1 (Update) URI 96-08-01: Switchgear Room Carbon Dioxide Suppression System l

Corrective Actions Review

During this inspection period, the VY staff completed the installation and testing of a low

pressure carbon dioxide fire suppression system for the East and West switchgear roorns.

This new system replaced the high pressure system which was determined not to be

capable of meeting design requirements (reference inspection reports 96-03,96-08 section

M2.1, 96-11, and LER 96-20). Prior to making the new low pressure systems operable, the j

licensee completed a comprehensive revision of operating procedure (OP)-3020, " Fire ,

Emergency Response Procedure." OP-3020 establishes the fire emergency response plans

for all fire incidents at the VY facility. The inspector noted that the licensee appropriately

examined the potential personnel hazards associated with the actuation of the switchgear

carbon dioxide suppression system and made significant changes to OP-3020. Extensive

training was conducted to ensure the control room staffs, fire brigade, and station 4

employees were cognizant of the new system's capabilities and potential personnel health

hazards. The inspector (,bserved that VY's actions to ensure personnel protection and

safety from actuation of the switchgear carbon dioxide suppression system were proper and

not compromised by pressure to meet earlier established scheduled commitments for

making the system operable. This unresolved item remains open pending inspector review i

of the new low pressure system design and pre-operational testing.

V. Management Meetings

X1 Exit Meeting Summary

The inspectors met with licensee representatives periodically throughout the inspection and

following the conclusion of the inspection on April 3,1997. At that time, the purpose and

scope of the inspection were reviewed, and the prelimina y findings were presented. The

licensee acknowledged the preliminary inspection findings.

X3 Management Meeting Summary

On March 12,1997, the Regional Administrator, Hubert Miller, and NRC staff met with

Hobert Young, Chairman of the Board, Ross Barkhurst, President and Chief Executor Officer,

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and the VY staff to discuss the March 5,1997 Systematic Assessment of Licensee

Performance (SALP) report in a public meeting held at the Vernon, VT Town Hall.

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X4 Vermont Yankee Management Changes

During this inspection period, Vermont Yankee announced the following management

changes:

i

e Frank Helin assumed the position of Technical Services Superintendent -

• Mike Watson assumed the new position of Maintenance Superintendent responsible

for mechanical and electrical maintenance, Instrumentation and Controls, and Work l

Control groups on site,

o Rick Gerdus assumed the positian of Chemistry Manager I

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e Jim Sinclair, Director of Public Affairs resigned from Vermont Yankee j

! X5 Review of Updated Finals Safety Analysis Report (UFSAR)

A recent discovery of a licensee operating its facility in a manner contrary to the UFSAR ' ,

i description highlighted the need for a special focused review that compares plant practices,  !

4

procedures, and parameters to the UFSAR description. While performing the inspections  !

discussed in liiis report, the inspectors reviewed the applicable portions of the UFSAR that

related to the areas inspected. Discrepancies that were noted were documented in the

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applicable section of the above report.

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INSPECTION PROCEDURES USED .

.

- '71707 Plant Operations '

62707 Maintenance Observations i

f 61726 Surveillance Observations

j 71750 Plant Support Activities

~

37551 Onsite Engineering

92700

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Onsite Follow-up of Written Reports of Non-Routine Events

93702 Onsite Response to Events

l' 37700 Design Changes and Modifications

j 82301 Evaluations of Exercises for Power Reactors

i 92702 Follow-up of Maintenance Activities

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ITEMS OPENED, CLOSED, AN $ DISCUSSED  !

CLOSED

4 URI 95-06-01 Review of "B" Main Station Battery Operability

1 IFl 96-10-01 Performance of On-Line Electrical Bus Preventive Maintenance

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URI 94-16-02 Adequacy of Instrument Loop Accuracy

!Fl 96 09-04 ' Alternate Rod Insertion Actuation

UPDATED ,

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URI 96-08-01 Switchgear Room Carbon Dioxide Suppression System Corrective

Action Review.

OPENED

IFl 97-02-01 Follow-up Licensee Actions to Address Single Failure Vulnerability of

the Primary Containment isolation Logic Circuity Documented in LER l

97-01

IFl 97-02-02 Review Licensee Long-Term Actions to Resolve the Residual heat

Removal Systems Alternate Keep-Fill Line-up Design Vulnerability

IFl 97-02-03 Monitor and Review Licensee's Final Assessment and Resolution of the

Turbine Building HELB issues q

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VIO 97-02-04 Violation of Technical Specification 6.5 and AP 0125 for improper j

Control of the De-energization of Bus 6 on November 25,1996

URI 97-02-05 Review the Licensee's Event Report processing of the AOG Neutrals-to-

Grounds Mixing issue (root cause evaluation).

IFl 97-02-06 Review Licensee Resolution of the Spare Battery Charger TS/ Design j

Conflict

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IFl 97-02-07 Review Licensee's Res sonse to NRR inquiries About Off-site Power I

Source Reliability

IFl 97-02-08 Review Licensee's Resolution of TS 3.5.D.3 Crediting Alternate Cooling

Systems for Service Water Subsystem Unavailability

URI 97-02-09 Instrumentation Loop Analytical Limits Exceed the TS Allowable Value

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PARTIAL LIST OF PERSONS CONTACTED

.

l G. Maret, Plant Manager l

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F. Helin, Technical Services Superintendent l

E. Lindamood, Director of Engineering

K. Bronson, Operations Manager

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M. Watson, Maintenance Superintendent

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M. Desilets, Radiation Protection Manager

R. Gerdus, Chemistry Manager

G. Morgan, Security Manager  ;

C. Nichols, l&C and Electrical Maintenance Manager ,

3

W. Wittmer, Mechanical / Facilities Maintenance Manager i

C. Rose, Work Control Manager l

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D. Legere, Systems Engineering Manager j

i B. Finn, Training Manager i

R. Wanczyk, Director of Safety and Regulatory Affairs

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LIST OF ACRONYMS USED

VY Vermont Yankee

NRC Nuclear Regulatory Commission

NRR Office of Nuclear Reactor Regulation

TS Technical Specifications

EDG emergency diesel generator

LER Licensee Event Report

YAEC Yankee Atomic Electric Company

YNSD Yankee Nuclear Services Division

SALP Systematic Assessment of Licensee Performance

PDR Public Document Room

RCIC reactor core isolation cooling

LCO limiting condition for operation

,

LOCA loss of coolant accident

LPCI low pressure coolant injection

RHR residual heat removal

HELB high energy lina break

EQ environmental qualification

RCA Radiation Control Area

RWP Radiation Work Permit

RP radiation protection

AO auxiliary operator

QA Quality Assurance

AOG advanced off gas

UFSAR Updated Final Safety Analysis Report

DBD Design Basis Documentation

ITS Improved Technical Specifications

TSC Technical Support Center

OSC Operations Support Center

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