ML20155B841

Operational Safety Team Insp Rept 50-267/88-200 on 880509-20.Major Areas Inspected:Operations,Maint, Surveillance,Mgt Oversight,Safety Review & QA Programs

ML20155B841
Person / Time
Site:	Fort Saint Vrain
Issue date:	09/02/1988
From:	Beckman D, Cummins J, Haughney C, Hunter D, Imbro E, Michaud P, Naidu K, Sharkey J, James Smith, Waters D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV), Office of Nuclear Reactor Regulation, PRISUTA - BECKMAN ASSOCIATES
To:
Shared Package
ML20155B840	List: ML20155B837 ML20155B841
References
50-267-88-200, NUDOCS 8810070101
Download: ML20155B841 (43)

See also: IR 05000267/1988200

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U.S. NUCLEAR REGULATORY COMMISSION

OFFICE OF NUCLEAR REACTOR REGULATION

Division of Reactor Inspection and Safeguards

Report No.:

50-267/88-200

Docket No.:

50-267

Licensee:

Public Service Company of Colorado

2420 W. 26th Avenue, Suite 15c

Denver, Colorado 80211

Inspection at:

Fort St. Vrain Nuclear Generating Station

Plattsville Colorado 80651

Inspection Conducted:

May 9-20, 19F8

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Team Leader:

wt s

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tes E. Cummins, Team Leader

Date

Se*nior Op ations Engineer, NRR

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Team Members:

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C Et gene V. Imbro, Chief, 'Igum Inspection

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Developmqnt S tion 2, ORIS, NRR

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Donald A. BecKman, Consultant, Prisuta-Beckman

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h vTd B. Waters, Consultant, Prputa-Beckman

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ssnciates

Other NRC personnel attending exit treeting:

Leonard J. Callan, Director,

DRP, RIV; Charles J. Haughney, Chief RSIB, DRIS; Thomas F. Westeman, Chief,

RPS-B, RIV; Kenneth L. Heitner Project Manager, PD4.

Approved By:

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. J. Haughney, Chief,4pecial Inspection Branch,

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ORIS, NRR

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TABLE OF CONTENTS

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PAGE

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INSPECTION SCOPE ........................................

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2.

DETAILED INSPECTION FINDINGS ............................

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2.1

Plant Operations

2.1.1

Observation of Operations Activities ....................

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2.1.2

Control Room Activities .................................

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2.1.3

Plant Tours and Inspections .............................

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2.1.4

Management Controls .....................................

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2.1.5

Procedure Reviews .......................................

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2.1.5.1

Emergency Operating Procedures (EPs) ...................

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2.1.5.2

Standard Operating Procedures ...........................

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2.1.6

Independent Verification ................................

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2.1.7

Equipment Clearances ............................ .. ....

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2.1.8

Valve Mispositioning ....................................

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2.1.9

Equipment Tagging and Labeling Program ..................

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2.1.10

Temporary Configuration Report Reviews ..................

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2.1.11

Remote Plant Shutdown ...................................

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2.2

Maintenance .............................................

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2.2.1

Maintenance Organization . ..............................

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2.2.2

Station Service Requests .. .............................

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2.2.3

Maintenance Activities Cbserved .........................

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2.2.3.1

Cold Reheat Steam Thermocouple Repairs ..................

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2.2.3.2

Steam Generator B-2-6 Trim Valve (TV-2228-6) Repairs ....

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2.2.3.3

HV-21243, Loop 1 Turbine Water Header

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Isolation Valve Repairs ...............................

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2.2.3.4

Bypass Flash Tank Drain Valve Repair ....................

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2.2.4

Engineering / Maintenance Interface .......................

18

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2.3

Surveillance Testing ....................................

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2.3.1

Organization and Scheduling .............................

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2.3.2

Procedures ..............................................

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2.3.3

Inservice Testing of Pumps and Valves ...................

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2.3.4

Measuring and Test Equipment Inaccuracies ...............

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2.3.5

Surveillance Activities Witnessed .......................

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2.4

Management Oversight and Safety Review ..................

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2.4.1

Staffing ................................................

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2.4.2

Plant Operations Review Committee .......................

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2.4.3

Nuclea r Facili ty Sa fety Comi ttee . . . . . . . . . . . . . . . . . . . . . . .

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2.4.4

Operation Information Assessment Group ..................

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2.4.5

Post-Trip Reviews .......................................

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2.4.6

Management Overview and Safety Review Weaknesses ........

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2.5

Corrective Action Programs ..............................

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2.5.1

Discrepant Report Tags - Initiation and Disposition .....

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2.5.2

Ongoing Activities Related to Maintenance and Repair ....

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2.5.3

Initiation and Disposition of Nonconformance Reports ....

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2.5.4

Internal Audit Findings .................................

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2.5.5

Corrective Action on Operating Events ...................

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3.0

ORAFT INFORMATION RELEASED TO THE LICENSEE ..............

36

4.0

EXIT MEETING ............................................

37

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ATTACHMENT A - Attendance Sheet for exit meeting on May 20. 1988

ATTACHMENT B - Copy of Information Released to Licensee

ATTACRMENT C - Abbreviations and Acronyms

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1.0 [NSPECTIONSCOPE

The primary focus of the inspection was to assess the safe operation of the

Fort St. Vrain Nuclear Generating Station (FSV). The inspection effort was

concentrated on control room operations and activities that related to

operations and supported the safe operation of the plant.

As a part of the

operations performance evaluation, the team observed approximately 120 hcurs of

shift operations, including backshift and weekend inspections,

in addition to

observing operations, the team inspected the areas of maintenance, surveillance

testing, management oversight, safety review, and quality programs.

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2.0 DETAILED INSPECTION FIND! HGS

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2.1 Plant Operations

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2.1.1 Observation of Operations Activities

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In this portion of the inspection the team assessed the overall adequacy of the

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licensee's operational management controls program implementatior by observing

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plant activities continuously and in depth.

A team of three ins;.ectors

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evaluated these activities and programs by combining around-the-clock on-shift

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inspections with routine day-shift inspections. The inspection emphasized direct

observation of the licensee's activities, rather than review of the program

content.

Control room and in-plant activities were observed around-the-clock for approxi-

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mately 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br />.

The inspectors observed key corrective maintenance, surveil-

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lance testing, and operations activities occurring during routine shifts.

The team evaluated the licensee's operational activities from the cold shutdown

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mode to criticality. The inspectors observed the following activities:

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(1) operations shift personnel perfonning their duties (personnel observed

included the shift supervisor, senior reactor operator, control room

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operators, equipment operators, and auxiliary tenders.)

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(2) conduct of control room operations

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(3) plant system alignments and plant startup activities

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(4) placing and removing of system clearances

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(5)

in-process surveillance testing

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(6) attendance at station management's post-trip review comittee meeting

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(7) plant tours to observe work in-progress and housekeeping

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(8) management's direct involvement in operational activities

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(9) all-discipline support of plant operations.

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Plant programs and procedures reviewed by the team included:

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(1) remote shutdown procedure

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(2) emergency operating procedures (EPs)

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(3) standard operating procedures (SOPS)

(4)

Independent Verification (IV) Program

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(5) controlled drawings

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(6) Temporary Configuration Program controls

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(7) overtime controls for operations, mechanical, and electrical maintenance

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(8) equipment clearance and operation deviation reports

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(9) equipment tagging and labeling program.

2.1.2

Control Room Activities

The team observed the conduct of operations in the control room.

Access to the controls area was restricted as is required by procedures and

NUREG-0737, Item I.C.4.

A professional atmosphere was observed in the control

room, and distractions such as music and non-job-related reading materials

were excluded.

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Operating procedures and references, including the latest revisions and indices,

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were readily available. Drawings in the control room were current approved

revisions. An expanded sampling of about 170 drawings were reviewed to assess

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clarity and quality of information provided. Of the 170 drawings reviewed, 7

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had portions where information was either missing or very difficult to read.

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The drawings reviewed were Piping and Instrument Drawings PI-1 through PI-45-8

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inclusive. The following problems were noted:

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PI-21-7

Valves and instruments added because of plant modifications were

very faintly indicated and equipment numbers were difficult to

discern.

PI-21-8

Valves and instruments added because of plant modifications were very

faintly indicated and equipment numbers were difficult to discern.

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PI-11-1

Areas of the drawing were obscured and fuzzy. Some setpoint values

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and instrument numbers were incomplete and unreadable.

PI-31-3

Information on portions of the drawing was crowded and small text

could only be read with the use of a magnifying glass.

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PI-33-1

Some valve and line numbers were unreadable.

PI-42-2

Gray background that resulted from poor reproduction quality made

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information unreadable,

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Approximately 25 EL series electrical drawings were also evaluated for read-

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ability; no readability problems were identified.

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The licensee advised the inspectors that this problem had been previously iden-

tified and that actions were being taken to eventually convert the plant drawing

system to a computer-aided drafting system.

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The operators were observed to adhere to procedures and routinely referred to

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procedures during the conduct of cont'o1 room operations. The inspectors also

noted during observations and interviews that the operators were very knowledgeable

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dhd strived for good plant operations.

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The coninunications between shift personnel were effective and included good

shif t turnover briefings, start-of-shif t triefings by the shif t supervisor,

and information briefings before major plant operations. The plant manager and

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operations superintendent were frequently observed in the control room

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checking the plant status and consnunicating with shift personnel. The team

considered this a strength.

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A review of the shift logs revealed the following weaknesses:

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(1) Entries were too brief.

(2) Operations performed were not entered in some logs. However all

significant operations performed could be retrieved by reviewing the

shif t supervisor, senior reactor operator, and reactor operator logs.

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More attention needs to be paid to log entries for all shift logs

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including the equipment operator and equipment tender logs.

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Too many control board annunciators had nuisance alanns (not actual alarm

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condition) for the exist'.t.9 plant operating mode. The licensee was working

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toward the goal of a dark annunciator board.

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2.1.3

Plant Tours and Inspections

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During the team inspection, several tours of the plant were made to observe

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plant housekeeping conditions, equipment conditions, and compliance with proce-

dure and program requirements. During the early portion of the inspection, the

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plant was in a shutdown condition and maintenance was ongoing in several areas

of the reactor building. Toward the end of the inspection period, the plant

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was in a startup condition.

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The general condition of the plant from a housekeeping perspective was very

good. Cleanliness controls were evident and containers for contaminated

clothing and for waste were not overly fu'l.

In areas in which maintenance

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was not t,eing performed, materials were nd allowed to accumulate to unmanage-

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able levels. The team observed maintenance personnel moving through the

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reactor building cleaning oil accumulations from components and equipment and

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removing debris.

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Several areas of concern and weaknesses noted during the tours were brought to

the licensee's attention.

The licensee addressed all of these and either

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initiated or completed corrective action before the team left the site.

These

areas arc detailed below:

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(1)

In several instances, equipment used in servicing, surveillance, or

maintenance activities was lying loose on the metal grating on several

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levels or was stored on top of installed equipment.

Examples are:

pipes

used to support the moisture monitor closure flange were lying loose on

the deck or on top of one of the prestressed concrete reactor vessel

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(PCRV) penetrations, valve wrenches were placed atop valve operators,

scaffolding materials that were not in use were not secured to the oeck,

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and ladders were not rehung on racks or fixed in place.

If left

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unsecured, these items could cause damage to safety-related equipment

during plant operation.

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(2) On level 4 of the reactor building in the cubicle containing the gas

blowers, several supports on a line in the vicinity of valves V-63117 and

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V-63118 were broken loose from the baseplates mounted in the floor,

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(3) On level 7 of the reactor building, fire hose rack RH7J2 was noted as not

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having all hose loops properly pinned in the rack. Upon closer inspection,

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it was noted that the hose nozzle had a piece broken off the diffuser

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portion, which would change the spray pattern of the nozzle from its

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design.

(4) On level 5 of the reactor building, the wooden deck of a four wheel cart

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had not been painted with fire-retardant paint, as is required by

Administrative Procedure SOAP-8, "Plant Signage and Labeling Programs,"

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issue 1.

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(5) The licensee had located two Scott Air-Pak bottles in clamp-type holders

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on the wall next to the elevator on level 1 of the reactor building to

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provide backup breathing air capability in the event of a fire or

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radiological incident.

The team questioned if the restraining device for

the bottles could keep them from becoming a missile hazard if the bottles

should fall and rupture during seismic activity.

The licensee could not

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document the adequacy of the installation, but infortred the tearu that the

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problem would be investigated and resolved.

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During a tour with one of the equipment operators, a valve was noted to be

leaking around the packing.

The operator informed the team that a procedure

was in place to adjust minor packing leaks without requiring a station service

request and thus expedite leak reduction efforts. The procedure for control of

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this program was MAP-6, "Valve Packing Adjustrnent," Issue 2.

The team reviewed

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this procedure and iloted that the effect of packing adjustments on stroke titres

for valves with operators was not addressed.

It was possible that packing

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adjustments could affect the stroke time of valves required to close or open

within certain times as defined in Technical Specifications and potentially

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render them inoperable. However, the team found no examples in which stroke

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time was affected. The licensee responded that it would investigate this area;

if stroke-time-sensitive valves could be affected by this procedure, the

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program would be revised to ensure that the valves remain operable.

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During walkdowns with operations personnel, the team observed a sound level of

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knowledge and familiarity with the location and operation of plant equipment,

This gave the team confidence in the operators' ability to perform their job

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functions and to respond to abnormal occurrences.

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2.1.4

Managetrent Controls

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The licensee's overtime controls for the operations,trechanical, and electri-

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cal groups were reviewed. The review period covered approximately two months,

Only one minor deviation from Technical Specification guidelines was found.

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This shows a strong comitroent to adhere to the Technical Specification

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guidelines.

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The inspectors attended the licensee's post-trip-review comittee meeting on

May 12, 1988.

The purpose of this meeting was to establish the causes of the

events associated with the reactor trip on May 6, 1988.

This review was

conducted in accordance with procedure SMAP-7, "Fost Trip Reviews,"

Issue 6.

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This procedure required that a documented review be performed to determine the

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feasibility of a reactor restart after an unscheduled reactor trip,

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The intpectors observed representatives from all licensee departmeats at the

meeting, exceeding the requirenents for a quorum; personnel a:tively partici-

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pated in discussions until a consensus was reached.

The n.eeting scope far

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exceeded the post-trip-review requirements.

This broadly based management

involvement was considered a strength.

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2.1.5

Procedure Reviews

2.1.5.1

Emergency Operating Procedures

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The licenste's emergency operating procedures (EPs) were reviewed and emphasis

was placed on the planned revision to the emergency procedu.es to achieve

compliance with NUREG-0737, ' Clarification of TMl Action Plan Requirements "

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and with Supplen.ent I to NUREG-0737, subtitled "Requirements for Emergency

Response Capability."

The current emergency procedures (EPs) were event oriented, and contained a

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number of events which could be reclassified as abnormal events.

Procedures EP

A. "Moisture Indeakage," Issue 54, and EP B-1, "Reactor Scram," Issue 54, were

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reviewed as samples. The procedures consisted of a symptom / action matrix,

which correlated immediate actions and followup actions for the turbine (west)

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side and the reactor (east) side control room operators with symptoms obtained

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from annunciators or control board meters.

The procedures contained several

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immediate action steps which the operators were required to memorize. This, in

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combinationwiththelargenumber(norethan20)ofEPs,requiredahighdegree

of operator knowledge to link the symptonis to the action steps and then iden-

tify the event accurately in oraer to determine the followup actions.

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Considering operator stress as a factor dsring off-normal events, the proce-

dures may be difficult to apply efficiently and accurately.

The licensee

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acknowledged that the current procedures need to be improved and that a signi-

ficant improvement should be realized once the revised EPs are implemented.

The program for improving the EPs was described in the licensee's letter of

April 10, 1987, as including the Procedurer Generation Package, a proposed

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Writer's GJide, and a Program Plan for the Integrated Validation of NUREG-0737

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initiatives, hRR was then reviewing the program.

The utility expected fin &l

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review and approval of the program within the next several months so that the

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new procedures night be implemented by the end of the fourth refueling outage,

or approximately mid-1989.

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The licensee intended to utilize a flowpath approach for controlling the events

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arising from an upset cor.dition as opposed to t,he symptom / action matrix. The

flowpaths will be syrptom oriented, and will be applied to the control of tran-

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sient events following a reactor scram as well as the restoration of critical

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safety functions. The critical safety function parameters will be monitored by

the safety parareter display system and will adoress five areas of control:

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reactor flux, primary system, !,econdary system, prestre1 sed concrete reactor

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vessel (FCRV) integrity, and radiation.

The team reviewed the planned safety

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parameter display system inputs as well as draft flowpaths for critical safety

function restoration and found that the nethods being employed appeared to be

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appropriate and were consistent with the approaches being taken by other

utilities. The licensee indicated that the bulk of the current EPs would be

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redefined as abnormal operating procedures and that the safe shutdown cooling

procedure set would be incorporated as part of the EP set,

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The licensee dedicated two individuals to the EP developrnent prcgram, one of

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whom was an experienced shif t supervisor. The schedule for flowpath procedure

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develcpment, revies, verification / validation, training and implementation was

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very aggressive. Even though the program appeared strong because of the high

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quality of the individuals assigned to the project and the availability of

other plant personnel who had much operational experience, additional resources

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tray be required hring the development phase to enable irnplementation of a

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quality product by the comittrent date.

It was also observed that the shift

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supervisor involved in the project had been occasionally diverted from the EP

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oroject to handle other procedural problems, such as those arising from the

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recent emergency plan team inspection; such diversion could weaken the effort.

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The adequacy of the resources assigned to the upgrading of the EPs was con-

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sidered a ptential weakness if management does not maintain its priorities,

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As part of the emergency operating procedure reviews, the team reviewed the

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safe shutdown cooling procedures to assess the capability of auxiliary tenders

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or equipnient operators to perform as operators.

These procedures were not

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part of the EPs, but were contained in a separate volurre cf the plant operating

manual. However, the licensee intended to incorporate these procedures into

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the upgraded EPs. The following procedures were reviewed'

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SSC-01,

"Restoration of Power to Essential 430 Volt Busses," Revision 1

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SSC-02,

"Steam Line Rupture Detection and Isolation System

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(SLRDIS) Reset Procedure," Revision 1

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SSC-03,

"Recovering From a Noncongested Cable Area Fire Resulting

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in an Interruption of Forced Circulation," Revision 1

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SSC-04,

"Recovery From SLRDIS " Revision 1

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SSC-05,

"Design Basis Earthquake /Maxirnum Tornado Recovery," Revision 1.

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Attachment 1 to SSC-01 was a checklist for lineup of alternate cooling method

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backfeed to essential buses which was to be performed by the auxiliary tender,

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Ouring a walkthrough of the checklist by the team and a qualified auxiliary

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tender, a weakness was observed.

The procedure step to position or verify

position of the four switches inside the 277-V lighting panel could not be

simulated because with the breaker in the, closed pcsition (as required by the

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previous step) the panel could not be operied.

The licensee stated that this

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problem had been previously identified, but the procedure had not yet been

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corrected.

It was observed that equipment required to accomplish the checklist

was available in the dedicated cabinet in the alternate cooling methods cubicle

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(e.g., a screwdriver and rubber safety gloves). A copy of the procedure was

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also located in the alternate cooling method cubicle for use by the operator.

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The team noted that procedures and system drawings were strategically located

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throughout the plant, which was a strength.

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Attachment f to SSC-03 provided instructions for the auxiliary tender to set

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the circulator's brake and seal frorn the helium storage area, a remote manual

activity. During the walkthrough of this attachment for circulator 1A, a

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weakness was observed because the steps to set the brake and seal require

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opening a locked cabinet door to gain access to the valves.

The door of the

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cabinet was hinged on top, and had to be lifted to a position just past verti-

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cal. The possibility existed that the door could have fallen closed and

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injured the operator during the activity required by the procedure, thus

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disatling him from completing further required actions. The licensee indicated

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that it would investigate altering the hinging of the doors to the cabinets in

question. The operator was observed to have the necessary key to open the

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cabinet, and a copy of Attachment 2 to SSC-03 was available to help the opera-

!

tor in the imnediate area of the valves that required tranipulation.

!

!

Attachment 7 to SSC-03 provided an operator aid for the equipment operator to

I

read thermocouple temperatures from the temperature transmitter located in the

j

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auxiliary electrical roun, During the walkthrough of this attachment, two

i

minor weaknesses were observed:

(1) The Fluke thennocouple reader was not

(

j

located in the shift supervisor's office as referenced in the attachment but

l

!

was located in the control room and (2) the standard screwdriver required to

j

connect tne thermocouple reader to the temperature transmitter was not dedica-

1

j

ted to that specific use and was not located with the Fluke instrument.

The

!

licensee stated that the Fluke instrument had been relocated to the control

[

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j

room to provide a more secure area for control of the instrument, but the

!

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procedure had not been revised to reflect this change. The screwdriver was

I

supposed to be taped to the handle of the Fluke meter, but someone had used it

j

and placed it in a desk drawer in the control room.

i

Attachment 5 to SSC-04 provided instructions for installing a through flange

between the firewater system and the errergency feedwater header.

During a

4

walkthrough of this attachment with an equipment operator, two weaknesses were

{

observed:

(1) Drain valve V-45947 did not have a tag and could not be verified

'

as the correct valve and (2) the mechanical spreader referenced in steps 7

'

!

and 10 of the procedure could not be found in the sealed toolbox dedicated to

!

perfomir.g this procedure.

It was observed that the platform and toolbox

,

required to perform this procedure were located near at hand and had been

{

sealed against unauthorized use.

'

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t

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Attachttent 1 to SSC-03 provided a table for defeating interlocks associated

!

i

with valves, controllers, or other plant equipment which may become disabled

'

as a result of fire or other situations arising from plant transients.

The

a

required actions included pulling fuses or confiming the integrity of fuses,

,

installing jumpers at terminal blocks, or removing a grill cover and actuating

!

,

relays located behind the grill.

During a walkthrough of the attachment with

$

d senior reactor operator, three weaxnesses were observed:

(1) ror Sv-210c,

the attachment required the operator to pull fuses F-254 and F-134 at 1-05;

however, fuse F-254 did not exist and (2) a dedicated supply of fuses for

replacing blown-out fuses had not been provided; (3) the grill at the bottom

of panel 1-10. Bay 800 could not be removed by use of a screwdriver since

,

i

one of the screws had been replaced by a hex head bolt. The licensee replaced

1

this bolt and other simil6r bolts in grill covers with screws, and will

{

investigate the other areas identified.

.

l

It was observed that the operations personnel assisting the team in the walk-

i

through were knowledgeable of the procedures, the actions required, and the

locations of the referenced equipment.

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,

An overall weakness was failure to periodically walk through the procedures and

attachments to ensure that all required equipment was in place and ready for

-

use. Licensee action to correct the above procedure and material deficiencies

is an unresolved item pending further review by NRC Region IV (267/88200-01).

,

I

2.1.5.2 Standard Operating Procedures

The team reviewed selected standard operating procedures (SOPS). These proce-

dures, as many of the other plant procedures, were undergoing major revision as

i

part of the licensee's procedure upgrace programs.

The procedures reviewed

l

were:

l

S0P 21-01

"Helium Circulators," Revision 20

1

$0P 21-02, "Helium Circulator Auxiliary Systems " Revision 72

d

"

SOP 22-01, "Steam Generators " Revision 45

!

S0P 31,

"Feedwater and Condensate Systems " Revision 43

L

"

S0P 32-01 "Secondary Coolant System - Feedwater Heaters," Revision 3.

t

The review determined that several of the procedures, in particular 50P 21-01,

}

SOP 22-02, and 50P 32-01, contained a number of valve lineup changes and

>

complex activities without an associated checklist.

The lack of a prepared

!

checklist for these manipulations means that they must be copied from the

j

procedure in the field, possibly introducing error. Additionally, there was

no sign-off by the operator to indicate completion of the actions nor was

i

l

independent verification of safety-related valve manipulations required. This

I

j

was considered a weakness in an otherwise satisfactory program for controlling

and verifying equipment position. The licensee stated that the provision of

i

checklists would be investigated. Confirmation of licensee action in this

j

regardisanunresolveditempendingfurtherNRCRegionIVreview(267/88200-02).

2.1.6 Independent Verification

The licensee's independent verification program was reviewed with regard

.

to implementation in the equipment clearance program, repositioning or

r

reterminating equipment following surveillance testing, and positioning of

l

valves and other plant equipment following outages or major work on systems.

'

The licensee's independent verification program has been previously inspected

and found to be acceptable with respect to the requirements of NUREG-0737.

j

j

ltem !.C.6 (NRC Inspection Report 82-27).

The team found that the surveillante

tests reviewed contained required steps for independent verification of criti-

2

cal equipment returned to normal status if the procedure had been revised as

,

part of the procedure revision program.

For those tests that have not yet

been revised, independent verification steps have been added by procedure

i

!

change when the test is performed or will be added the next time the test

j

was performed.

,

l

The licensee has independently verified each valve contained in the system

I

valve list (SVL) for all plant systems.

The SLY contained manual valves such

as isolation valves, and vent and drain valves. This was a strength because

all critical and noncritical valves woulo be independently verified anytime a

i

system lineup was conducted. Valves with operators were considered "instru-

i

atnts" as well as being considered operational valves (controlled by operating

1

procedures) and were not included in the SVLs. The licensee indicated that a

j

system lineup would not necessarily be conducted on a system unless major work

j

was performed during an outage; this implies that valves could be manipulated

i

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,

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,

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during normal operation over an extended period without being independently

j

1

verified. Hofever, there was some indication that the licensee was considering

,

{

conducting system walkdowns including independent verification on a more

(

regular basis. Confirmation of licensee action in this regard is part of

,

unresolved item 267/88200-02, Section 2.1.5 of this report.

i

SMAP-19. "Processing Equipment Clearances and Operation Deviations," Issue 7

F

1

controlled equipment removed from and returned to service.

The procedure

f

required independent verification that all clearance cards and auxiliary tags

(

were placed properly and were removed when the work was completed; that the

-

.

equipment, annunciator, or instrument had been properly isolated before work on

!

1

it began and properly returned to normal before testing or returning to

l

)

service, and that all sealed and critical valves would be independently veri-

{

fied for proper resealing and correct positioning before the equipment, annun-

l

!

ciator, or instrument was returned to service.

This program was considered

.

I

acceptable and appeared to satisfy the requirements of NUREG-0737.

2.1.7 Equipment Clearances

I

]

r

i

The team reviewed the active clearance book during preparation for plant

f

]

startup and identified two weaknesses associated with the proper administration

I

i

of the independent verification requirements of SMAP-19. "Processing Equipment

!

)

Clearances and Operation Deviations." On May 12, 1988 Clearance No. 21136 was

,

l

conpleted to place helium circulator C-2101 out of service without independent

l

verification of two valve positions. The valves were isolation anc bypass

i

valves on the non-safety-related auxiliary portion of the system, and were

!

,

j

subsequently confirmed to be in their required position. On May 15, 1988,

l

Clearance No. 21155 was completed to place the reactor building sump filters

<

out of service without independent verification of the sump pump hand switch

i

positions. The switches were not safety related and the hand switches were

i

subsequently confirmed to be in their required position.

In both cases, the

i

i

independent verification blocks on the clearance form had not been initialed as

l

I

required, indicating that independent verification had not been performed for

!

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this equipment.

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2.1.8 Valve Hispositioning

Both the Institute of Nuclear Power Operations (INPO) and hRC had identified

concerns related to valve mispositioning incidents. The team reviewed proce-

I

dure P-1, "Plant Operations," Step 4.6.4.c.1, which directed the operator in

1

the correct method of checking manual valve position. The team questioned

Training Department personnel about operator training on valve positioning for

different classes of valves, such as gate, globe, or butterfly; considerations

related to valve backseating; how to determine positions of locked or sealed

valves and ensure locks ano seals are properly applied; and other considera-

tions which have been the subject of INPO Safety Evaluation Reports and INP0

Significant Operating Event Peports. After the team reviewed auxiliary tender

and equipment oper4 tor training program materials, the licensee reported that

the subject was not currently addressed in their training program. Training

,

-

deficiency report (TDR) Ko. 051388 1 was issued on May 13, 1988, to develop a

f

lesson plan for auxiliary tender trainees on the subject of valve operations,

NRC review of the training ceficiency report's resolution is an unresolved

i

)

item pending further NRC Region IV review (267/88200-03).

I

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)

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2.1.9 Equipment Tagging and Labeling Program

The team reviewed the licensee's equipment tagging and labeling program.

The

program was controlled by plant procedure SOAP-8, "Plant Signage and Labeling

Policy " Issue 1, which controlled the identification of components, pipes,

rooms or equipment for the improvement of maintenance, operation, and perfonn-

ance.

The procedure was specific in defining label or sign sizes, colors,

l

method of attachment, and stendards for descriptions used on the signs.

huREG 0700 and thP0 OP-208 were used as guidance documents in developing the

I

program.

Independent verification was enployed to ensure signs and labels were

applied correctly.

l

The program hed been under way for approximately six months, and progress was

l

evident. Problems had been identified with existing plant labels and steps had

been taken to correct them through the implementation of this program. The

operations group had worked an average of 40 to 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br /> of overtime per week

to identify and apply signs and labels.

The emphasis had been placed on

consistently identifying major safety-related valves and electrical components

such as motor control centers, as well as other equipment, components and

piping. The licensee anticipated full plant compliance with Procedure SOAP-8 by

the end of 1988.

This program was considered a strength because the licensee was acting aggres-

sively to implement this program.

Personnel who had extensive plant experience,

including a retired shift supervisor, were involved in ad:ninistration of the

program and ensuring its compliance with procedures.

It appeared that plant

personnel in general were highly supportive of the program and recognized its

importance to operation, maintenance, and surveillance activities.

2.1.10 Temporary Configuration Report Reviews

The team reviewed the Temporary Configuration Report (TCR) Log for completeness

in accordance with procedure SMAP-18 "Processing of Temporary Configuration

Reports," Issue 4, dated Nover.ber 19, 1987.

This procedure described the

controls and steps for processing temporary changes to plant equipment.

During

this review, the inspectors found that three active TCRs, 88-03-05, 88-04-01,

,

l

and 88-05-03, had not been entered in the TCR index.

Procedure SMAP-18, step

4.1.1, required the index to be updated when a new TCR was initiated. The

.

significance of an incomplete index was that lifted leads, jumpers, and other

'

temporary equipment changes were tracked only by TCRs. Missed TCRs could

result in inoperable safety significant equipment.

l

l

Open ICRs dating back to 1985 were found, but none of these dated TCRs were

safety significant, and a major effort to close these out was in progress.

Licensee action to ensure correctness of the TCR log and reduce the lacklog of

old open TCRs is an unresolved item pending further NRC Region !Y review

(267/88200-04).

2.1.11 Remote Plant Shutdown

,

The team reviewed the procedure for remote shutdown outside of the control

rcom.

This procedure review and walkdown identified the following weaknesses:

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(1) Only the licensed operators were trained on remote shutdown every two

years.

The team was concerned about the frequency of training and the

lack of training for unlicensed operators who must be used for remote

plant shutdown.

(2) Training every two years consisted of walkdown of the procedures and did

[

not simulate the event by a coordinated team drill.

An additional

,

weakness was that instructor involvement in the procedure walkdown was too

I

cmall to evaluate the weaknesses and provide input to retraining.

This training deficiency became even more significant if a fire was the

!

cause for control room evacuation, since three operations personnel were

assigned to the fire brigade and may not be available to help with the

remote shutdown.

-

Additionally, no remote shutdown test has ever been perfonned.

This raised

I

significant concerns about the ability to integrate operation of equipment,

which has been independently tested, but not tested on an integrated basis.

Licensee attention to these weaknesses appears warranted:

Inadequate training,

ninimum operations staff required for remote shutdown concurrent with a

'c

fire, and whether an integrated test of remote shutdown capability should be

perfonr.ed are an unresolved item pending further NRC Pegion !Y review

,

(267/38200-05).

!

0.2 Maintenance

Themaintenanceinspectionconsistedofobservationsmade(1)during)the

licensee's performance of four corrective maintenance activities (2 reviewing

approximately30stationservicerequests(SSRs),(3)andreviewingselected

tr,aintenance procedures. On the basis of these inspection activities, the team

reached two general conclusions.

First, the team was concerned about the

licensee's control of maintenance activities and the adequacy of work instruc-

!

tions. Second, the tecm was impressed with the level of knowledge and skill

i

demonstrated by the craftsmen.

The toam noted an apparent relationship between

'

poor quality work' instructions and work being perfonned without written

i

procedures.

,

After reviewing work activities and interviewing craftsmen ano supervisors,

the inspection team concluded that the first-line supervisors were well aware

6

of inadequacies in maintenance procedures and documentation of maintenance

l

activities. The team further determintd that these procedure and documenta-

!

tion problems had apparently not been communicated to management, nor had any

j

correctise action been initiated,

i

I

On the basis of oiscussions with region based personnel, recent inspection

I

reports, the latest systematic assessment of licensee performance (SALP)

i

report, and licensee program changes in progress, it appeared that significant

improvements have been recently effected to bring the maintenance progran into

l

agreenent with industry standaros. These improvements, on a relative scale.

!

were considerable; however, on an absolute scale, the licensee's maintenance

program lagged behind the industry by a considerable margin.

For example, the

l

licensee was in the process of reestablishing the basis for the Preventive

l

Maintenance program. Vendor maintenance recomet,dations, equipment operating

i

history, and regulatory requircrtents were being reviewed as part of this

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d

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effort.

In addition, the Maintenance Superintendent stated that sophisticated

'

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maintenance programs, such as predictive maintenance utilizing thennography and

i

vibration analysis, were planned for the future.

However, the development of

j

the planned maintenance had to be complete before the improved maintenance

j

progranis could be instituted,

i

j

The team noted a positive attitude on the part of most maintenance personnel

'

contacted during this inspection.

In general, maintenance technicians realized

.j

that the past practice of conducting maintenance without administrative con-

trols was unacceptable. Additionally, the technicians seemed to have a feel

!

for the relative safety importance of the equipment they were working on. They

j

,

i

stated that they relied on the SSR classification to determine the equipment's

t

j

safety-related classification.

h]

2.2.1 Maintenance Organization

I

While the team was on site, the licensee reorganized the Nuclear Production

'

i

Division to produce a more streamlined division.

Before the reorganization,

'

the instrumentation and controls (l&C), mechanical, and electrical maintenance

f

disciplines were under two separate superintendents. The I&C technicians were

!

,

i

under the control of the Nuclear Betterment Engineering Superintendent; the

.

mechanical and electrical technicians were under the control of the Maintenance

l

Superintendent. The reorganization placed all three maintenance disciplines

under the control of the Maintenance Department Manager.

,

.,

2.2.2 Station Service Requests

Work was authorized, controlled, and documented for plant maintenance using the

SSR and its associated work package as described in procedure P-7, "Station

Ser;i & Request Prucessing," Issue 13. The SSR for any individual maintenance

-

task consisted of a control documert and attachments, referred to as an SSR

l

work package. Documents that iccccpanied an SSR incluced: procedures, such as

controlled work procedures (CKPs) and corrective maintenance procedures;

,

special instructions, including supervisor's instructions; excerpts from

approved documentation; drawings; supporting documentation, such as

i

nonconfonnance reports (NCRs), design changes (DCs), and other documents that

-

,

expanded on the work plan,

J

i

l

Plant instrumentation and equipment that were required by the Fort St. Vrain

l

!

(FSV) Quality Assurance Progran to be maintained at the highest level of

1

quality attainable were classified as safety related/ enhanced quality SSRs.

l

As required by Procedure F 7, these SSRs received enhanced material control,

maintenance, and documentation considerations per 10 CFR 50 Appendix B, the

,

(

FSV Station License, Final Safety Analysis Report (FSAR), and other regulatory

{

documents. Procedure P-7 further stated that equipment classified as

j

safety-related/ enhanced quality required quality control (QC) services and

i

other activity as a consequence, and completion of reviews on the $bR form

j

otherwise not required.

The equipment classification was determined by the

3

Scheduling and Planning Cepartnent with assistance from the Operations

l

i

Department.

Procedure P-7 also defined special processes (e.g., welding,

]

heat treating, nondestructive examination) as requiring QA/QC.

,

'

1

)

in the performance of a complicated task, a "chained" SSR could result. A

I

chained SSR was defined as being supplementary to an existing SSR and was used

1

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to direct a support activity to a primary job task. A chained SSR was denoted

I

by a numerical suffix attached to the primary SSR number. As an illustration.

l

a primary job task SSR would be numbered 8800500-00; a chainto SSR to this task

would be numbered 8800500-01.

.

!

Plant Procedure P-7 allowed the maintenance supervisor or planner at the job

[

site to make pen-and-ink changes to the SSR. if the scope of the work statenent

i

was not* changed. The computerized version of the SSR did not have to be

updated. The team noted that the potential for losing the content of the pen.

and-ink changes was considerable should the original SSR (which was also the

fieldcopy)belost.

Several of the SSRs reviewed by the team contained

j

nurr.erous pen-and-ink changes.

If an SSR with significant pen-and-ink changes

'

was lost or destroyed, it would be difficult or impossible to recover the

informa tion. Additionally, the potential existed for adding work requirenents

i

that would not be appropriately reviewed by site engineering and quality

1

i

assurance personnel.

2.2.3 Maintenance Activities Observed

The inspection team observed portions of four maintenance activities focusing

l

on work planning, performance, documentation, post-maintenance testing, and

'

quality control effectiveness.

The team reviewed the controlling administra-

i

,

tive procedures for these programatic areas to verify correct implementation

'

,

during performance of the actual work. The team's observations noted for each

observed maintenance activity are discussed in the materia.1 that follows,

i

)

2.2.3.1

Cold Reheat Steam Thermocouple Repairs

Station Service Requests (SSR) 88502797. 88502827, and 88502823 were issued to

-i

remove damaged themoccuples TE 2256-1. TE 2255-5, and TE 2255-3 respectively.

Thermocouples TE 2255 5 and TE 2256-1 were stuck in their thermowells and

TE 2255-3 had damaged conduit.

The inspection team followed the work on the

retroval of the damaged thermocouples over the course of the onsite inspection

i

period. At the time the team initially began to follow the work, themoccuple

TE 2256-1 had been electrically disconnected and the electrical leads on the

thermocouple had been removed. The work authorized to be performed under

primary jcb task SSR 88502797 is sumarized in the table that follows:

Suffix

Approval Date

Work Description

00

May 7, 1988

Troubleshoot current loops per drawings

referenced on attached. Note any

i

disconnections and/or reconnections

during troubleshocting. Contact I&C

Department to originate SSRs against

l!

any bad instrument.

l

l

01

May 7. 1988

Retrove/ reinstall insulation as

,

required in support of Results

i

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Engineering work.

i

]

02

May 8, 1988

Heat up thermowell in accordance with

map-15 in order to remove thermocouple.

l

Themowell is safety-related pressure

l

boundary only.

.

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Suffix

Approval Date

Work Description

I

03

May 11, 1988

Drill out broken thermocouple as

required.

NOTE:

Thermowell TW-2256-1 is

safety-related. Contact l&C

j

Department when work completed.

1

J

The team began its observation on May 11, 1988, inspecting the work described

in suffix 03 and following the work through completion.

It is important to

i

,

.

note that the thermocouple was classified as not safety-related and that the

!

j

thermowell itself was classified as safety-related.

The following observations

!

were made concerning this maintenance activity:

'

3

(1) The $5R work plan stated, "Remove seized section of themocouple as

I

l

appropriate." Maintenance technicians were observed drilling into the

I

safety-related thermowell without having appropriate drawings of the

.

thermowell; the SSR work description did not provide any information on

j

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the depth, diameter, or tolerances of the thermowell, nor did the

!

!

attached OC inspection sheet contain any of this information. The SSRs

!

shoulo be more specific leaving less latitude and placing less reliance on

'

the "skill of the craft."

'

(2) Special drill bits consisting of a regular bit welded to an extension

,!

shaf t had to be manufactured to drill out the thermowells. Apparently,

'

the manufacture of the extended drill shaft was not controlled under an

l

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SSP., and the material compatibility of the drill bits and thermowell

l

material was not considered.

i

'

(3) No procedure was provided for conducting the ost-maintenance test,

'

)

which was a hydrostatic test of the thermowel

(seeSection2.2.4

l

of this report for a discussion of hydrostatic testing).

i

I

(4) A welding roo was placed down inside the themowell and was momentarilj

'

energized using a foot switch to remove two broken drill bits from the

,

l

themowell .

This technique was referred to as using a "stinger."

'

Application of this special process pursuant to 10 CFR 50, Appendix B,

j

i

criterion IX was not controlled. Apparently, an engineering review was

'

not conducted and the SSR work instructions did not address the use of

a welding "stinger." The SSR did not reference site welding procedures;

the requirements of P-7 Section 3.1.3f (QA/QC involvement during the

'

use of special processes) apparently were not observed; and the require-

i

ments of P-12. "Plant Maintenance," Issue 5, dated January 19, 1988, were

i

)

not observed. Section 3.9.3 of P-12 required that procedures for special

.

processes shall be reviewed and approved to ensure that the work was

l

performed in accordance with the required specifications.

Failure to

control the welding special process used for the above activities is an

I

i

unresolved item pending further hRC Region IV review (267/88200-06).

<

,

(5)

Insufficient detail was recorded for maintenance history. The work done

portion of the SSR did not contain all infomation about the job - in

!

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particular, that the "stinger" was used to remove portions of the two

j

broken drill bits.

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(6) Two virtually identical maintenance activities were inconsistently

classified.

The work in both cases involved separating by drilling a

stuck non-safety-related thermocouph from a safety-related thermowell.

SSR 88502797 was classified as non-safety-related; SSR 88502827 was

classified as safety-related.

This was significant because involvement

of the Quality Control Department was contingent on the safety-related

classification of the $$R as defined in P-7, Section 3.1.3.

(7)

Inconsistent post-maintenance test requiretrents between these SSRs was

noted because the SSR classified as safety-related required a hydro-

static test but the non-safety related SSR did not require post-

maintenance testing.

(6)

$$R 8850287 was amended by a pen-and-ink change in the field to include

a hydrostatic test of the thermowell.

Since the original scope of the

SSR was to drill out the broken therinoccuple, a suffix to the SSR should

have Seen prepared and forn. ally reviewed,

in addition to unresolved item 267/88200-06, above, licensee actions

to correct the other maintenance pro

2.2.3.1(1), (2), (3), (5) gram and implementation weaknesses in

paragraphs

, (6), (7), and (8) are an unresolved

item pending further hRC Region IV review (267/88200-07).

2.2.3.2 Steam Generator B-2-6 Trim Valve (TV-2228-6) Repairs

SSR 88502035 was issued to repair a body-to-bonnet leak on the valve in ques-

tion.

The scope of the repair included a weld buildup and remachining of the

body-to-bonnet mating surface.

The function of this valve was to regulate

feedwater flow to steam generator module B-2-6.

Each steam generator module

!

had an assuciated trim valve (TV-2227-1 through TV-2227-6 and TV-2228-1 thr0 ugh

TV-2228 6).

By design, each trim valve was set so that, with the valve fully

shut, it would pass a minimum of 20-percent full-rated feedwater flow.

To

satisfy this requirement, each trim valve was set 1-inch off the shut seat when

the valve operator was in the fully shut position.

I

The inspection team observed portions of the valve reassembly. The team was

particularly interested in how the valve was set 1-inch off the shut seat to

ensure the mininum flow requirement was satisfied.

The team noted the

j

following discrepancies in the performance of this maintenance task:

(1) Maintenance technicians were observed disasserbling the valve stem coupler

without written procedures controlling the valve disassembly. The main-

tenance technicians had been instructed to verify the alignment of the

i

'

valve stem and the valve operator sten.

This was the setting that ensured

,

steam generator module B-2-6 had adequate flow when the valve positioner

was in the fully shut position.

(2)

Neither the work instructions nor the valve calibration data sheet

1

specifieo that the valve disc was required to be set 1-inch off the

shut seat with the valve operator fully shut.

[

(3) Nuclear engineering personnel were unable to justify the correlation

between the *1-inch off the shut valve seat" design requirement and scribe

i

marks on the vahe stem and operator sten, that maintenance technicians

4

,

used to set up the valve.

The scribe marks had been made sctre time in the

d

-16-

,

m -

-

.

m

.

.

. -

m

.. . ..

.

- .m

-

. .

- -

-

._ _ _ _ _ - _ _

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

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

_ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _

_ _ _ _

.

O

i

.

past and were routinely used by the maintenance technicians in setting the

,

valves. Maintenance technicians did not directly measure the "1-inch

l

off the shut seat" requirement.

Rather, the scribe marks on the valve

!

stem and the operator stem were set at 5 1/2-inches apart.

The date and

circumstances when the scribe marks were made could not be detemined,

4

yet the maintenance technicians relied solely on the scribe marks to

ensure that the minimum flow requirements were satisfied.

Failure to

i

maintain 20-percent flow could result in heat damage to the steam genera-

tor module.

(4) The maintenance technicians partially disassembled the valve when checking

the distance between the scribe marks, despite the absence of written

,

procedures and in the presence of a quality control inspector. The QC

l

1

inspector did not realize that the maintenance technicians were working

!

"

outside of calibration procedure, RP-900. When the NRC inspector ques-

'

,

tioned the maintenance technicians about the procedure they were using to

j

set up the valve and the basis for the 5 1/2-inch measurement, the QC

!

1

inspector stated that he had similar concerns.

i

'

l

10 CFR 50, Appendix E. Criterion V requires that procedures shall be "of a

[

2

type appropriate to the circumstances and shall be accomplished in accordance

with these... procedures....

Instructions shall include appropriate quantitative

I

1

cr qualitative acceptance criteria for determining that irportant activities

(

have been satisfactorily accomplished."

It appeared to the team that these

,

1

requirements had not been satisfied in the performance of this maintenance task

i

t

because the requirement to set the valve 1-inch off the shut seat was not

i

specified, the use of the scribe marks was uncontrolled and apparently without

.

any technical justification, and the disassembly of the valve stem coupler was

also uncontrollec.

Failure to provide acceptable instructions for setting the

1

stem on TV-2228-6 is an unresolved item pending further NRC Region IV review

,

!

(267/88200-08).

'

i

i

2.2.3.3 HV-21243, Loop 1 Turbine Water Header Isolation Valve Repairs

!

l

SSR 88502490 was issued to repair seat leakage and body-to-bonnet leakage on

I

valve HV-21243. The SSR was issued as a tracking SSR mechanism for nonconfor-

]

mance report (NCR) 88 0088. Repairing the valve involved weld buildup and

i

machining affected portions of the main seat and the body-to-bonnet mating

i

,

i

surface. This valve had a history of body-to-bonnet leakage, and temporary

l

I

repairs had been made before the outage by injecting sealant into the affected

i

I

area of the mating surface. The inspection team followed portions of the valve

(

)

machining and reassembly.

The team noted that, in conjunction with repairs

'

made to valve TV 222C-6, the licensee was for the first time using FSV crafts-

i

men to do the machining.

In the past, the licensee had contract machinists

,

perform this type of repair work. The team also noted considerable involvement

,

by the Nuclear Engineering Department in evaluating the as-found condition of

i

]

the valve internals while performing the root cause determination,

j

1

During observations of this maintenance activity the team noted poor house-

j

keeping practices at the job site. Debris from lagging removal was not cleaned

i

j

up until several days after the lagging had been removed and with th3 system

'

open to the environment. Maintenance Administrative Procedure (MAP) MAP-8,

)

• System and Con.ponent Cleanliness Requirements During Perfomance of Main-

tenance Activities," Issue 3. required that the work area be cleaned after each

J

operation that generates potential contaminants. Additionally, the valve

l

internals were left unprotected and untagged on the floor. MAP-7, "Parts

i

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--

-- -

- -

.

-

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.- .---

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_-

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.

.

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identification and Control," Issue 1 dated April 28, 1986, required that

l

maintenance personnel perfoming ths work shall ensure that component and parts

I

were packaged and identified as they were removed. MAP-7 elso required that

I

removed components and parts receive the required degree of protection while

.

they were removed from the system.

Failure to implemer.t procedures for

i

cleanliness control and material control is an unresolved item pending

j

i

further NRC Region IV review (267/88200-09).

l

2.2.3,4 Bypass Flash Tank Orain Valve Repair

!

!

During preparations for plant startup on May 17, 1988, control room licensed

i

operators experienced problems with LCV-32-17-1, the bypass flash tank drain

valve. The valve responded slowly to the demand signal and would not close

past the 40-percent open position.

$$R 88502982 was issued to troubleshoot

the valve and, calibrate it if necessary, and required that the SSR be

'

replanned if any other problems were detected. While troubleshooting, the

,

maintenance technicians found that the valve's instrument air pressure reducer

!

had a ruptured diaphragm. The SSR was returned for replanning, the pressure

!

reducer was replaced, and post-maintenance testing (stroking the valve from

I

the control room) was completed satisfactorily.

While observing this main-

!

tenance activity the inspection team noted no discrepancies.

2.2.4 Engineering / Maintenance Interface

'

The inspection team noted that the maintenance staff did not request

engineering involvement in non-routine or unusual naintenance activities that

could potentially compromise a safety-related system or function.

For extrrple,

.

before drilling out the themowell to remove the stuck thermocouple the main-

!

tenance staff should have consulted with the engineering staff, since the

i

thermowell was part of the safety related pressure boundary. Also, since no

hydrostatic test procedure exists at fort St. Vrain, engireering personnel

.

'

should have been asked by maintenance personiel to specify the test rig con-

I

figuration tc assure that (1) it included a rslief valve to prevent overpres-

!

surization of the themowell and that (2) the pressure gauge was installed in

such a mant.er as to preclude its being isolated and potentially giving an

l

erronecus reading;

Engineering personnel did specify the hydrostatic test

i

pressure and the curation of the test.

I

t

Theteamrcytewedthreenon-conformancereports(NCRs)associatedwithmain-

I

tenance activities related to the removal and replacement of themocouples

stuck in themowells.

NCR 88-127 addressed the cutting and rewelding of

thermowell TW E256-1 to retrieve pieces of a drill bit that had broken in the

themowell curing the attempt to rencve the stuck themoccuple.

NCR 88-131

accressed the replacement of the original 1/4-inch-diameter thermocouple with

a 3/16-inch-diameter thermocouple because the 1/4-inch themocouple could not

be fully inserteo into the thertrewell af ter the stuck thermocouple had been

drilled out. Both NCRs88-127 and 88-131 appeared acceptable in that the

dispositions adequately addressed the technical aspects of these NCRs. hCR

88-122 contained an evaluation of the thermowells to establish an appropriatt

hydrostatic test pressure to verify that the drilling process did not

cotrpromise the integrity of the pressure boundary. Although the evaluetion

demonstrated that the hydrostatic test pressure of 3000 psig would produce

stress five tirres greater than stresses seen in normal service with a large

rargin before the thermowells were overstressed, the team noted that the

evaluation referenced versions of ANSI Standard B31.1 and ASME Boiler and

-18-

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.

_ _ _ _

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l

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.

.

Presst + 1

el Code Section VIII that were not comitted to in the FSAR.

Since tse tuermowell design margins were so large, this did not raise a concern

i

of technical adequacy. However, the team cautioned the licensee that careless

'

or inappropriate use of codes and standards not committed to in the FSAR can

lead to future concerns regarding failure to meet licensing comitments.

'

2.3 Surveillance Testing

The inspection team reviewed the licensee's program for observing the testing

requirements imposed by the Technical Specifications (TS).

The review included

assessments of the responsible organizations; adequacy of procedures; accep-

tability of test resvits and rerolution of problems found during testing;

administration and scheduling of tests; and observation of test perfor ance.

2.3.1 06ganization and Scheduling

program Controls

The team reviewed the contents and implementation of administ ative procedures

applied to the Surveillance Program.

The principal controls ,ere provided by

SMAP-1, "Tecnnical Specifications Surveillance Testing Program," Issue 7;

SMAP-5, "Scheduling Program for Surveillances Governed by FSV Technical

Specifications," Issue 5; and NPAP-4, "Surveillance Procedure Preparation,"

Issue 3.

Each line department (e.g., Operations, Results, Maintenance, etc.) was madt

responsible for preparing and implementing surveillance tests applicable to

their areas of expertise via several TS procedure matrices.

These matrices

identified individual TS line item requirements, the corresponding implementing

procedure, procedure issue status, departmental responsibility, etc. and

provided an effective management tool for assuring satisfaction of each TS

surveillance requirement. The team found these administra+ive procedures,

matricos, and related working documentation acceptably implemented except

as noted below.

Scheduling

Surveillance test schedules were administered by the Planning ana Scheduling

Group and a Surveillance Scheduling Technician was dedicated to the task.

Computer-generated schedules were prepared weekly and the applicable test

procedures issued by the scheduling group bore a "scheduled date" and a "late

date" on the cover sheet of each procedure. The scheduled date was developed

,

from the last actual performance date and 'the late' date represented the actual

TS due date without application of TS allowed schedule tolerance (25-percent of

thesurveillanceinterval). The technician checked on test completion daily

and collected completed tests from performing departr ents. The technician also

revi v ed and signed the proceoures documenting completion, and entered the

performance data in the computer.

Postponed and failed tests were similarly

tracked but were specially identified to indicate their status. These activi-

ties ware checked very closely and the intensity of the approach appeared to be

very eff ective in controlling the status of testing and assuring that tests

were completed within the intervals required by the TS. No examples of overdue

testing were identified. All examples of failed or delayed tests found by the

team were identified and were being controlled by the licensee's system.

The

surveillance scheduling and accountability program was considered a strength.

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Although the mechanics of the surveillance scheduling and administration processes

j

appeared to be functioning satisfactorily, one discrepancy involving definition

of the TS surveillance intervals was identified.

SMAP-5, "Scheduling Program

for Surveillances Governed by FSV Technical Specifications," issue 5, generally

provided amplification of TS definitions and scheduling requirements. TS 2.15

defined "refueling cycle" surveillance interval as that (non-quantified)

interval between refuelings of greater than one-tenth of the core. No specific

interval in calendar time was provided.

Similarly, Si4AP-5 was silent with

regard to defining or discussing refueling cycle intervals.

Subsequent discus-

sion with the Manager, Nuclear Production determined that the licensee does,

however, apply the 18-month + 25-percent definition of standardized technical

specifications to the interval. The Manager, Nuclear Production stated that

the procedures would be revised to insure adequate procedure coverage.

Procedure SR 5.4.1.1.8.c-R, "Reheat Steam Temperature Scram Calibratior ," Issue

24, performed March 1987, was a refueling interval surveillance per TS. The

team noted that the entire instrument had been calibrated during March 1987,

except for the thermocouples that originated the process variable signal.

Discussions with plant managers revealed that new environmentally qualified

thermocouples had been bench calibrated upon receipt from their vendor in

December 1985 and held in storage until they were installed in late 1986 or

early 1987. Although iS 5.4.1.1.1.8.c specified a "refueling cycle" frequency,

'

PSC Action Reauest No.1875 had been issued to justify deferral of themocouple

recalibration for 18 months from the date the thermocouples were first exposed

to elevated operating temperature (about April 1, 1987). The justification was

based upon information f rom the equipment vendor, the Instrument Society of

America, and PSC Engineering which indicated that the thermocouple charateris-

tics were offected only by exposure to operating temperatures and would not be

expected to drift at ambient storage or cold shutdown conditions. The team

discussed the propriety and technical basis for this deferral with the licensee

and the NRC:NRR staff,

in the absence of a TS or other regulatory requirement

more quantitatively defining the refueling cycle interval and on the basis of

the licensee's technical justification, the deferral was considered acceptable.

2.3.2 Procedures

The team reviewed approximately 35 completed surveillance tests.

These proce-

dures were reviewed for conformance to TS functional requirements, frequency /

test intervals, acceptability of results, and adequacy of licensee disposition

of test deficier.cies.

The procedures included the general areas of plant

protection system testing, fluid system testing, fire protection, air and gas

system testing, electrical and diesel generator testing, and others.

Except as

noted below, no discrepancies were identified.

the team noted that the FSV "custom TS," dating from initial plant licensing,

.~requently provided only very general requirements for functional testing of

i

major systems.

The licenset was in the process of rewriting surveillance

9rocedures to meet curre.t industry guidelines and had effectively interpreted

a TS to broadly apply the generalized TS requirements to not only the major

systems but also to system auxiliaries and support equipment which contributed

to the operability of the major systems.

For example, the SR 5.2.20 series of

surveillance tests for the alternate cooling method (ACM) diesel generator

included testing of the batteries and auxiliaries implicit in the TS require-

l

nents but not explicitly listed. Similarly, Procedure SR-RE-80-X included

)

calibration of ACM instruments not explicitly required by TS.

The vintage of

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.

.

the TS had resulted in some limiting conditions for operation (LCOs) not having

corresponding surveillance requirements.

The licensee appeared to have exten-

sively evaluated the TS for such omissions and had issued surveillance procedures

for verification of conformance with these LCOs not having discrete surveillance

requirements. This application of operability concepts was considered a

strength.

The licensee was also working with the NRC staff to develop new TSs in the

standardized TS format and expected to issue proof and review draft TSs for NRC

review shortly after this inspection. This effort was expected result in

another major surveillance procedure rewrite effort (expected sometime in

1989). The licensee appeared to have the processes in place to effectively

make the transition from custom to standardized TS.

2.3.3 Inservice Testing of Pumps and Valves

The facility's Inservice Test (IST) Program was under development at the time

of this inspection.

As a high-temperature gas-cooled reactor (HTGR), FSV's

systems fall under Division 2,Section XI of the American Society of Mechanical

Engineers (ASME) Code instead of Division 1,Section XI (applicable to light

water reactors (LWRs)). Division 2,Section XI had not been approved / endorsed

by NRC and FSV had not yet implemented a full-scope IST Program.

Individual interim inservice testing requirements had been included in certain

Technical Specifications, e.g., TS 5.3.4, "Safe Shutdown Cooling Valves Surveil-

lance." Typically, these TS requirements did not specifically invoke the ASME

XI provisions but merely required "operability" or "functional" testing of

components. Although the licensee was connitter ; use the provisions of ASME

XI as guidance, no overall program description r 1mponent test matrix had

been developed.

Individual test requirements were addressed only in the

individual implementing procedures.

Similarly, no program for collation and

trending of equipment performance data typically required of IST programs had

been implemented. Such a progrom was under development at the time of inspec-

tion. As a result of the above ambiguities in the IST Program development,

several discrepancies were identified in implementation of the existing TS IST

requirements during review of Procedure SR 5.3.4bl-A, "Loop 1 Safe Shutdown

Cooling Power Operated Valve Tests," Issue 5, performed on April 16, 1987.

TS 5.3.4 required an annual "full functional test" of the system valves and

provided progressive implementation requirements for various valve typt 3

through the cycle 5 refueling. Table 11 in this procedure listed seven sets of

valves which were identified as exempt from testing with the justifyino annota-

tion "normally operates." The same was true for the Loop 11 procedure SR 5.3.4.b2-A.

None of the valves exempted by the licensee appeared to fall under

i

the delayed implementation requirements of the TS nor thE exemption or deferral

provisions of the NRC safety evaluation reports of the applicable TS Amendments

Nos. 33 and 51.

On May 17, 1988, the licensee provided the team with a list of procedures

which coincidentally exercised all the valves for Loops I and 11 except for

valves HV-2153 -1 and

-2, bearing water filter isolation valves. Although

these procedures did not perform preplanned testing of the valves, the licensee

considered that the coincidental operation met the requirements of their

program, processed Procedure Deviation Reports to incorporate the tests into

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.

.

SR 5.3.4.bl-A and SR 5.3.4.b2-A, and documented the test performances.

The

HV-2153 valves were subsequently tested on May 12, 1988 because equivalent,

existing data was not available.

The team also requested the licensee to identify any other procedures that may

contain similar inappropriate exceptions. On May 18, 1988, the licensee advised

that Procedure SR 5.2.7 al-A, "Loop I/II Valves and Circulator Drive Tests,"

Issue 3, included an exemption for valve V-22371, emergency feedwater (EFW)

header check valves. At the end of the inspection, the licensee was evaluating

the availability of existing, coincidental test data and the applicability of

f orward/ reverse flow testing requirements for this valve.

NRC review of the

results of the above licensee actions to ensure all valves subject to IST are

not improperly exempted is an unresolved item pending further NRC Region IV

review (267/88200-10).

The team considered the absence of an overall program control document to be a

major detractor from effective definition and management of the program in that

essentially no guidance had been provided to either procedure writers or test

conductors.

2.3.4

Measuring and Test Equipment Inaccuracies

As part of the licensee's post-trip review of a reactor scram occurring on May 6,

1988, control problems were identified with the reheat steam temperature control

circuits.

Troubleshooting from May 6 through May 14 identified several circuit

and equipment problems.

The conduct of licensee post-trip review and problems

regarding thermoccuple removal, repair, and reinstallation are discusseo in

Section 2.1.a and 2.2.3.1, respectively, of this report.

The team also revie nd the calibration-related problems with the reheat steam

temperature controls. This control loop was considered not to be safety-related

and was not subject to TS. Accordingly, it had been routinely calibrated on a

modular basis; no complete loop checks were performed which would test the

circuit from input (thermocouple output) to control output (reactor flux

control / rod movement). The circuit apparently had been operating with about a

35'F offset in actual reheat temperature vs. the demand control signal.

The

licensee subsequently determined that the offset was caused by a suspected

loose lead in one of the circuit's averaging sub-loops; the licensee had

completed a full-loop circuit check and was planning to incorporate the full

loop check intt future calibrations.

i

During this trot.bleshooting, the licensee encountered difficulties in obtaining

stable module calibrations between bench and field calibrations.

Initially,

early in the week of May 9, 1988, the digital multimeters used for testing were

suspected to have drif ted out of the manufacturer's calibration tolerances.

The loop was subsequently recalibrated using test meters known to be good.

I

On about May 16, the licensee seterm%ed that meter test leads were improperly

connected to the meter for se

Er all of the reheat steam temperature control

troubleshooting and recalibration.

The meters had two positive and two nega-

tive female test lead jacks for measurement of voltage, resistance, or current.

Except for current measurements, selection of any positive and negative jack

combinations was apparently acceptable and resulted in accurate measuren.ents.

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.

.

.

However, for current (milliamp) measurements such as used for this activity,

only one combination of jack installation was acceptable and incorrect combina-

tions can and did result in significant meter errors.

Procedure RP-A-04, "Requirements Governing the Control and Calibration of Test

Equipment and Standards," issue 6, Section 4.5, "Out of Tolerance Conditions,"

provided requirements for evaluation of prior use of out-of-calibration equip-

ment to ensure that installed instruments were recalibrated if defective test

equipment may have been used on them. When the team inquired late on May 16,

1988 about the identification and operability status of safety-related instru-

ments potentially calibrated with the affected meters, the responsible instrument

and control supervisor advised that the evaluation had not been started, even

though plant restart had initially been scheduled for May 15, 1988 had been

delayed, and was then scheduled for the night of May 16-17, 1988. The team

considered this failure to recognize the need to establish the operability and

calibration status of potentially affected safety-related instruments as a

weakness in the area of licensee management controls and attention.

Apparently as a result of the team's inquiry, the evaluation was conducted from

the evening of May 16 through May 17, 1988 and approximately 100 uses of five

meters were evaluated.

Eleven cases of safety-related uses requiring calibra-

tion rechecks were identified; of these eleven, two were found to be out of

tolerance and were recalibrated. Another 11 cases of non-safety-related

uses of the meter were considered to require rechecks, and rechecks were

scheduled for the week following plant restart.

The team reviewed the detailed

records used for the licensee's evaluation and found the evaluation acceptable.

2.3.5 Surveillance Activities Witnessed

i

Surveillance test performance was observed to determine that the procedures

were properly performed and satisfied the referenced TS requirements, that

coordination between plant operators and test performers was adequate, that

treasurement and test equipment was properly calibrated and applied, that test

results were pr merly acquired and evaluated, and that problems were properly

handled. The team witnessed part or all of the following surveillance tests:

SR 4.1.1.d-X, "Full Stroke Scram Test," Issue 3, May 12, 1988

SR 5.4.1.1.4.b-P, "Wide Range Power Channel Test," issue 26,

May 16, 1988

SR 5.4.9-A2, "Process Beta Monitors Calibration " Issue 26,

Section 5.5, RT 31193, "SJAE Process Flow," May 16, 1988

SR 4.1.1.1.14.a-M, "Plaht 480 Volt Power Loss Test," May 17, 1908.

All observed testing was considered satisfactory by the team except for Sk

5.4.1.1.4.b-P as further discussed below.

As previously discussed, the licensee was completing a major rewrite of TS

surveillance tests to meet current industry format and content standards,

2

1

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_

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.

Procedure SR 5.4.1.1.4.b-P, "Wide Range Power Channel Test," functionally

tested the logarithmic nuclear instrument channel interlocks, rod withdrawal

prohibits, and scrams.

The procedure had been initially reissued as Issue 25

in the new format.

During its first performance, the licensee found that the new procedure,

prepared using the vendor's Operations and Maintenance Manual (0&M) No.

93-I-1-335, included testing of an interlock circuit which would generate a

.

single channel scram when the "Wide Range Channel Level Calibrate Switch" was

'

removed from the "Operate" position.

This circuit feature was not actually

installed in the plant equipment. Nonconformance Report No.88-030 identifying

the above discrepancy was issued on February 18, 1988 and was resolved to "use

as is" pending long-term investigation and evaluation by the licensee. The

team reviewed the licensee's NCR disposition finding that, although appearing

contradictory with respect to the controlled vendor information, the absence of

the circuit appeared to have negligible safety significance.

The log level

portion of the channels did not have any normal scram or rod-withdrawal-prohibit

outputs; only the unaffected startup rate portion of the channels generated

either a scram or rod withdrawal prohibit signal.

Further, the Updated Safety

Analysis Report (USAR) took no credit for any log channel scrams in the

various accident analysis scenarios of USAR, Section 14. The licensee had not

been able to cetermine when or why the circuit was deleted from the equipment

and was following up the problem with the nuclear steam supply system (NSSS)

vendor.

At the time of discovery in February, the procedure was temporarily changed

via a Procedure Deviation Report (PDR) to delete the inapplicable tests and

reconfigure the procedure for performance. On May 4-6, 1988 the procedure was

,

'

reissued as issue 26, incorporating some administrative changes in procedure

completion and signoff forms, but inadvertently reinstating the erroneous

procedure steps addressing the nonexistent scram signal. Although the proce-

dure went through the routine review and approval steps, the licensee did not

identify the error.

On the 0000-0800 shift of May 16, 1988 initial attempts to perfonn Issue 26

of the procedure were unsuccessful when the procedure was found to have

inadequate instructions for establishing the necessary initial conditions and

clearing existing scram signals (plant shutdown).

The inapplicable level

switch scram steps had been marked "N/A" but had been left in the procedure.

During the 0800-1600 shift on the same day, the team observed a second attempt

to perform the procedure following approval of a PDR to reset the shutdown

scrams.

This attempt wds initially unsuccessful because the PDR was incom-

plete.

Following issuance of a second PDR to set initial conditions, the

inspector witnessed another unsuccessful attempt to calibrate the "A" channel

of the wide range power nuclear instrument.

The procedure, as written, includ-

ing the inapplicable steps, did not provide a smooth, sequenced instruction and

resulted in the technician having extreme difficulty placekeeping and maintain-

ing the functional sequence of the test.

For example, bistable alarms and

indicating lights from previous steps were not always reset, preventing the

technicians fror, determining whether the lights had merely remained on from

prior steps or had reflashed as a result of the current step.

Similarly, the

actual system responses did not match the procedure's expected responses with

the scram interlock circuit missing.

Additionally, the procedure had been

partially signed off by the previous shift which caused some confusion fcr the

s

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subsequent shift continuing the procecure at the proper step.

In response to

the difficulties encountered, the licensee issued PDR No.88-340 during the

evening shift of May 16, 1988, deleting the inapplicable steps and correcting

the remaining steps. The poor quality of the initial and revised procedure

had the potential for an inoperable reactor protection channel to go undetected

by the testing.

During review of other completed tests and operating procedures discussed

elsewhere, the team had also noted that several of the procedures had required

one or more PDRs to correct the originally issued versions to permit

performance. The licensee routinely issued full-page changes when a procedure

was modified by PDR, thereby reducing the chances for error inherent in issuing

piecemeal changes. However, the need to issue multiple changes to a recently

reviewed and approved procedure indicated weaknesses in the process for main-

taining accurate and current procedures.

As a result of the apparent frequency of PDR use and the performance-based

observations, the adequacy of the licensee's procedure review, validation, and

approval practices was identified as a concern to PSC management.

The PSC

$

Systems Engineering Manager, Results Supervisor, and others on the licensee's

i

staff discussed plans for creating a Plant Operations Review Comittee proce-

dures subcomittee which was in the planning stage and which was intended to

improve the procedure publication process.

These plans included a procedure

verification and validation process.

The team further reviewed the last two years' data for PDR usage, noting that

for the approximately 3690 total procedures, more than 1300 PDRs had been

issueo during calendar year 1987.

In contrast, about 340 PDRs had been issued

for 1988, or roughly one-half the number issued in 1987. Although the trend

appeared to indicate a declining use of PDRs as the new format procedures

have matured, the team remained concerned that the overall procedure approval

process was weak.

2.4 Management Oversight and Safety Review

The general functions of conraittee activities and safety assessment were

reviewed and included the staffing, the onsite review committee, the offsite

review comittees, the operating information assessment group, and the

post-trip review activity. The review included selected procedures and records

and personnel interviews regarding the implementation of the activities.

The

plant staffing appeared to be adequate and the May 12, 1988 reorganization

appeared to be a positive step toward impr,oving the operations and support of

the facility. The overall impact of the reorganiz'ation was not assessed during

the inspection.

The plant operations onsi.te review comittee (PORC) activities

appeared to be adequately implemented.

The inspection revealed that the review

function could have been more effective with regard to the use of telephone

poll (voting) reviews and the content of the PORC charter, including adequate

specific guidance for all activities.

The Nuclear Facility Safety Comittee (NFSC) activities appeared to be a strong

function.

Strengths included the specific use of NFSC members as technical

auditors in the areas of expertise and the provision of the NFSC meeting

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minutes to all NFSC members and alternates for review and consnent, as

appropriate. Three noteworthy observations were made regarding the NFSC

dCtivities:

(1) The NFSC planned to meet more frequently than once each six

months, (2) almost all meetings were conducted onsite at the visitor's center,

where the plant staff could easily attend; and (3) it was apparent from review

of the minutes and through discussions, that the NFSC was aggressive regarding

reviews.

The operating information assessment group (OIAG) activities (FSV, industry,

and NRC operating experience) appeared to be acceptable.

However, the

distribution of reports of items reviewed by the 01AG and the OIAG program

status reports was, limited and did not include all the facility managers nor

the Vice President, Nuclear Operations NFSC chairman.

The review of the NRC

Information hotice No. 87-25 appeared to be limited and could have been more

comprehensive (See Section 2.4.4 of this report).

Finally, even though the

intent of the OIAG function may have been addressed, the 01AG activities were

not being fully implemented in accordance with the procedure requirements.

The post-trip review activities appeared to be adequately implemented.

The

practice of utilizing a formal multidiscipline post-trip review of all reactor

trips and the established post-trip review concittee for reviewing all reactor

trips routinely and condition III reactor trips (complicated) prior to plant

restart was considered a good system.

Procedure SMAP-7, "Post Trip Reviews,"

Issue 6, did not require all plant transients to be reviewed. The other

transients were generally being reviewed, however, at the option of the Station

Manager.

2.4.1

Staffing

The facility appeared to be adequately staffed.

The licensee management was

sensitive to the potential staffing problems that could arise because the

nuclear plant had an uncertain future. The nuclear production department was

hiring acditional personnel, operators were being trained in order to obtain

an NRC operator license, and work on a limited plant simulator was progressing.

Further, a reorganization of the Nuclear Operations Department was effective

May 12, 1908. The reorgalization addressed the consolidation of engineering

activities, elevation of the training department to a division level, the

focusing of planning and scheduling activities, and the streamlining of the

nuclear production (plant) division. The Quality Assurance Division continued

to report directly to the Vice President, Nuclear Operations, as noted in the

Fort St. Vrain license. The licensee was working activ 4

fth the NRC, making

the organization changes required in the license.

2.4.2

Plant Operations Review Connittee

The PORC function was specified by Procedure NPAP-2, "Charter for Plant

Operations Peview Cona.ittee for Fort St. Vrain Nuclear Generating Station,"

issue 2, which impt smented the requirements of Technical Specification AC

7.1.2, "Plant Oper,tions Review Conmittee (PORC), Administrative Controls."

The minutes of five PORC meetings (Nos. 763-767) were reviewed.

Selected

personnel were interviewed regarding the PORC activities.

A team member

attended a PORC training / seminar ccaducted on May 11, 1988 and observed the

POPC meeting (No. 777) conducted on May 12, 1988,

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The FORC conducted meetings routinely at weekly intervals, generally on Tuesday

afternoon. The PORC reconvened during the week, as necessary, to review other

items requiring prompt attention.

It was noted that although Quality Assurance

Department (QAD) personnel attended the scheduled PORC meeting; they did not

attend the reconvened meetings.

Interviews revealed that the items reviewed by

the PORC during the reconvened meetings were reviewed by QAD as part of the

routine QA activities.

It was also noted that the PORC review, conducted on February 20, 1988, at

4:00 pm (Saturday), a reconvening of Meeting No. 765, took place by telephone

and included the Chairman, three members, and two alternates - no QAD represen-

tative. The review included a change notice (CN 2763), a controlled work

procedure (CWP 88-0036), and a functional test (2763) associated with the D-

circulator speed / cable repair and/or replacement activity.

Review of the PORC

minutes and interviews revealed that telephone reviews did not usually take

place. However, the practice of performing telephone reviews may not meet the

full intent of the TS, in that the PORC (quorum in session) meets and recomends

to the Manager, Nuclear Production approval or disapproval (in writing) of

items and rendered determinations in writing with regard to whether or not the

item constituted an unreviewed safety question.

Section 3.3.3 of NPAP-2,

regarding the conduct of business, item (a), allowed the use of "telephone

polls" as situations dictated.

The review of reportable events was addressed in Section 4.6 of procedure

NPAP-2; however, the procedure requirements were not inclusive of internally

generated 10 CFR Part 21 reports. These may not be reportable under 10 CFR 50.72/50.73 which were reviewed routinely by the PORC.

Section 4.7 of

procedure NPAP-2 addressed the forwarding of other matters to the PORC for

review, including 10 CFR Part 21 reports, as part of the review of facility

operations to detect potential nuclear safety hazards.

The review of

proceaure G-8, "Compliance With 10 CFR 21 Requirements," revealed that the -

procedure did not specifically address the PORC review of the 10 CFR Part 21

reports.

Interviews indicated that 10 CFR Part 21 reports were reviewed routinely

by the PORC.

The review of the PORC meeting minutes revealed that the documentation of the

matters discussed could be more comprehensive in order to provide a better

independent review of the PORC activities by other PORC members and alternates,

NFSC members and NFSC alternates, and QAD auditors.

Furthermore, it appeared

that the number of questions documented in the NFSC minutes regarding the

subject matter documented in the PORC minutes, could have been reduced by

improving the content of the PORC minutes.

The review of PORC minutes and interviews with license personnel revealed that

the PORC was reviewing plant procedures as required by Technical Specifications

utilizing a memorandum from the associated department; however, the PORC

charter, NPAP-2. Section 4.1, noted that the "existing procedures... reviewed

by PORC in accordance with SHAP-11." Procedure SMAP-11 was deleted on

December 1, 1986.

The review of PORC minutes and discussions revealed that the PORC minutes were

not provided routinely to all members and alternate members of the PORC for

their review and coment. The minutes were only provided to those persons who

attended the specific PORC meeting.

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2.4.3 Nuclear Facility Safety Committee

The NFSC function was specified by the "Charter for the Nuclear Facility Safety

Comittee for Fort St. Vrain Nuclear Generating Station", Issue 5, implementing

the requirements of Technical Specification AC 7.1.3, "Nuclear Facility Safety

Comittee (NFSC), Administrative Controls." The minutes of six NFSC meetings

(Nos. 108-113) were reviewed. Selected personnel were interviewed regarding

the NFSC activities.

The NFSC charter addressed the requirements of the Technical Specification and

contained liberal of guioance to assist in the performance of the NFSC activi-

ties. The review of the NFSC charter and the NFSC minutes revealed that the

NFSC charter appeared to have recently been substantially improved. The charter

addressed two specific subcomittees formed to assist in the area of licensed

activities: Special Test Review Subcomittee and the Startup Test Review

Subcomittee. Also an NFSC QA Subcomittee was established to perform

the required NFSC audits in concert with the QAD. The performance of the

required audits under the cognizance of the NFSC routinely included NFSC members

as part of the audit team.

The practice of using NFSC members as auditors was

'

considered a strength as the technical content of the audits appeared to be

good and NFSC members were more closely involved in the independent overview

of facility departments.

I

The NFSC charter, Section 10.0, addressed the meeting frequency requirements

of at least once each six months; however, reviews and discussions revealed

that the meetings were scheduled and conducted more frequently than required.

Additionally, the NFSC meetings were held on site at the visitor's center in

most cases, providing access to the meetings by the plant staff.

Document

review and discussions revealed that the minutes were routinely provided to all

the hFSC members and alternates for review and comment, even if the persons had

not attended the scheduled meeting.

Review of the NFSC minutes and discussions indicated that the NFSC appeared to

be a strong independent review group. At times, NFSC personnel asked many

questions; answering these questions apparently required substantial effort.

The questions, at times, were asked because the PORC minutes provided to the

,

'

NFSC did not include complete information. As noted previously, this area

could possibly be improved to obtain more effective, efficient, and timely

NFSC reviews. Overall, the NFSC appeared to be an aggressive review group.

The NFSC conducted telephone polls (voting) on a limited basis.

Section 4.2.8

of the NFSC charter allowed voting by telephone, when "it is desirable to

expedite the voting action." The item or document in question was identified

in the minutes of the next NFSC ineeting.

The review of minutes and discussions

confirmed the practice.

The review of reportable events (LERs) and Part 10 CFR 21 reports was required

by Section 43 of the NFSC charter.

The review of procedure G-8, "Compliance

With 10 CFR 21 Requirements " evealed that the procedure did not specifically

address NFSC review of the 10 CFR Part 21 reports.

Interviews and review of the

NFSC minutes revealed that 10 CFR Part 21 reports were routinely reviewed by

the NFSC.

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2.4.4

Operation Information Assessment Group

The 01AG function was specified by procedure NPAP-1, "Fort St. Vrain Nuclear

Generating Station Operation Infonnation Assessment Group Charter," Issue 4,

implementing NUREG-0737, Item I.C.5, "Feedback of Operating Experience." The

inspection revealed that the licensee had aJdressed the independent safety

engineering group in correspondence to the NRC in 1980, and the licensee was

not required to implement a safety engineering group, as acdressed by

NUREG-0737, item I.B.1.2.

Accordingly the licensae had not implemented an

independent safety engineering group and the review of in-house and ou'. side

operating experience was provided by the OIAG within the te:hnical services

engineering group. The details of the receipt, logging, review, independent

review, results reporting, and periodic 01AG program review were provided in

!

procedure TSP-28. "Conduct of Technical Services Reviews for the Operating

Information Assessment Group (0IAG)" Issue 3.

The designated OIAG Chairperson, the OIAG Coordinator, and the OIAG Senior

Engineering group provided the initial logging, screening, reviews, and

distribution of information for review and consideration fur action.

Document

reviews and discussions revealed that, with exceptions, the OIAG program

appeared to be functioning.

Following the initial screening of incoming information (SOER, SERs, IENs,

etc.) by the OIAG, the information was forwarded to the training department

for reproduction and transmittal to the designated groups, as appropriate.

The 01AG reviewed the FSV events for applicability, both in-house and external

(industry), which were considered by the group routinely. The source of the

FSV operating experience reports (0ERs) included licensee event reports (LERs),

procedure changes, transient analysis reports, change notices, control work

procedures, and facility license changes. Additionally, the OIAG had generated

a number of FSV OERs, Attachment NPAP-1c, as a result of other operating

events, including the circulating water pit flooding June 12, 1986 and Loop II

restart /cooldown May 4, 1987. The OERs were generated in order to fully assess

the events and provide appropriate feedback to the plant programs, procedures,

and personnel.

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During the inspection period on May 12, 1988, a reorganization of the Nuclear

Production Division was announced.

The OIAG function was planned to be trans-

ferred to the Nuclear Licensing Department.

The plan was to maintain the 01AG

function to ensure effective and timely review and actions regarding in-house

and industry experience.

Licensee actions to improve and ensure the OIAG's

continuing effectiveness is an unresolved item pending further NRC Region IV

review (267/88200-11).

The review of the OIAG meeting minutes and other general OIAG corresponounce

revealed that the OIAG reports were given a limited distribution.

All

appropriate managers and the Vice President, Nuclear Production /NFSC Chairman

were not included.

The team reviewed the OIAG processing of NRC Information Notice No. 87-25,

"Potentially Significant Problems Resulting From Human Error Involving Wrong

Unit Wrong Train, or Wrong Component Events." The NRC information notice was

noted to be received on June 18, 1987, and was assigned a number, G-87198, for

review and tracking purposes.

On July 21, 1987, the OIAG coordinator noted on

the OIAG review sheet (TSP-28A) that immediate attention was not required. An

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independent review was noted as applicable and on July 24, 1987, the independent

reviewer noted that the actions regarding the notice was to "route to operations

FYI only." The OIAG Chairman concurrence with the above actions "route ops" was

j

noted on July 27, 1987.

The team did not note evidence of a detailed review of

the references in the notice, including NUREG-1192," An Investigation of Contribu-

tors tc Wrong Unit or Wrong Train Events" (label ng); IE Infomation Notice 84-51,

,

"Independent Verification"; IE Information Notice 84-58, "Inadvertent Defeat of

l

Safety Function Caused by Human Error Involving Wrong Unit, Wrong Train, or Wrong

System"; and numerous NRC AE00 reports and four supplemental reports specifically

addressing the subject of the notice.

The review of the overall 01AG activity

revealed that, even though the reviews were being performed, the 01AG was not

being fully implemented in accordance with the OIAG Charter, NPAP-1, Issue 4.

Monthly meetings to review the operation of the program and ensure proper

functioning were not being conducted per NPAP-1, Section 2.0.

Therefore,

the screening process was not being "reviewed in the regular meetings by the

members" per NPAP-1, Section 3.6.1.5.

Routine internal audits had not been performed "to assure that the OIAG

program was functioning effectively," per NPAP 1 Section 3.6.1.7.

These

audits were to have been reviewed during the regular me'etings.

Reviews and

discussions revealed that a program review had been performed on December 29,

1987, at the request of the OIAG chairperson; and a QAD audit of the 0!AG

function was scheduled later in 1988.

Interviews revealed that the OIAG cheirperson felt that the intent of the OIAG

function was being n.et because discussions were being held routinely at the

daily (morning) superintendent meeting, although the discussions were not well

documented.

The failure to fully implement the OIAG function per the approved charter,

procedure NPAP-1 was considered a weakness.

This weakness was discussed with

licensee management for their consideration.

2.4.5

Post-Trip Reviews

The post-trip review function was specified by procedure SHAP-7, "Post-Trip

,

Reviews" Issue 6.

The program / procedure provided a "consistent, comprehensive

and systematic method to diagnose the causes of and conditions associated with

j

unscheduled reactor trips." The reviews provided the basis for making a

i

detemination about safe reactor restart. At the Station Manager's option,

the procecure was used for transients other than reactor trips.

'

The review of controlling procedure SMAP-7, and selected transient review

packages revealed the activity to be quite comprehensive.

The transient review

function consisted of multiple-discipline reviews, including the shift opera-

ting personnel, results engineer, technical advisor, and other plant personnel,

ds appropriate. A transient review committee (TRC) review was required before

restart for a Condition !! reactor trip (complicated) as was written permission

from the Station Panager.

The TRC reviewed all reactor trips during regularly

scheduled meetings including Condition I and !! reactor trips (uncomplicated)

j

although this was not required.

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The establishment of the post-trip review function appeared to be a good method

for reviewing trips and provided a multi-disciplined review with some amount of

independence and determination of immediate or short-term corrective actions.

The ultimate responsibility for plant restart rested in all cases with the

Station Manager / Manager, Nuclear Production.

However, the post-trip review

procedure was not fully inclusive of all plant transients but was applied at

the Station Manager's option for transients other than reactor trips.

The

inspection revealed that some of the transients had been revie ved by the TRC;

however, the review of all required transients (corrplicated) v as not a require-

ment in procedure SPAP-7.

This observation was discussed with licensee manage-

ment for their consideration.

2.4.6 Management Overview and Safety Review Weaknesses

The inspection team concluded that the apparent primary contributors to the

weaknesses described in paragraph 2.2 above were poor licensee management

overview controls and inadequate communications between first-line supervisors

and higher levels of management. This conclusion was based on interviews of

personnel, observations of maintenance and surveillance testing activities in

progress, and the noted weak procedural guidance available.

2.5 Corrective Action Programs

The team reviewed the implementation of the F8V quality assurance program

relative to corrective actions taken in the following areas:

- discrepant report tag (DRT)

- ongoing activities related to maintenance and repair initiation and

disposition of nonconformance reports (NCRs) internal audit findings

- operating events.

The review included discussions with knowledge personnel perfoming the work,

review of records in document control, and attendance at post-trip reviews and

outage scheduling meetings.

i

2.5.1 Discrepant Report Tags - Initiation and Disposition

The licenste uses DRTs to identify equipment and component problems requiring

corrective action or repair.

The most recent NRC Systematic Assessment of

Licensee Performance (SALP) 50-267/87-06 discussed prior problems with the

licensee's inadequate and slow corrective' actions.

The team reviewed the

following DRTs to determine the effectiveness and timeliness of the corrective

action applied.

(1) DRT 11853 was affixed to the low-pressure separator pump motor, that

separated helium and water. The relevant SSR 88502740 was initiated on

)

May 4, 1988 to identify that the pump motor was running roughly.

Corrective action isolated the purrp, replaced the motor bearings, and set

the flow per procedure SR 5.4.9-A1.

This equipment was a

non-safety-related item (NRI).

(2) ORT 005604 was affixed to an NRI pressure differential transmitter used

to monitor the moisture level in the helium cooling medium.

SSR 87507903

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was initiated on August 6,1987 to replace the existing flexible hose

connecting the condulet and the instrument with a longer hose.

(3)

Internal leaka

vessel (PCPV) ge from the bottom of the prestressed concrete reactor

pipe cavity air handling unit resulted in DRT 005610. SSR

87508684 was initiated August 18, 1987 to open the unit, investigate the

leak, and repair was required.

This was an NRI.

(4) The inboard and outboard mechanical seal of the safety-related cooling

water pump IC, Loop 11 leaked in excess of 30 drops per minute.

DRT

002182, dated May 11, 1988 was affixed to this equipment.

SSR 87508759

identified this as a safety-related component and included corrective

action to replace both mechanical seals.

The technical specifications

required that at least one cooling water pump must be operating in each

of the two PCRV cooling water loops during the reactor at power level

(LC0 4.2.13). The SSR required post-maintenance testing per procedure SR

RE-55-X.

Review of the above DRTs and SSRs, and subsequent discussions with the

cognizant planning and scheduling personnel indicated that in these instances,

the delay in implementing the corrective action was justifiable.

,

2.5.2 Ongoing Activities Related to Maintenance and Repair

The team observed maintenance activities in progress for two thermowell repairs

and maintenance on feedwater trim valves.

As discussed in Section 2.2.3.1 of

this report, the procedures and practices applied to these activities were

considered unacceptable by the team.

Although some of the activities were subject to QC inspection, no action had

been taken by QC inspection personnel to question or stop obviously

noncomforming activities.

These matters were ultimately brought to the

attention of the Plant Manager who promptly stopped the work.

The team

subsequently interviewed a QC inspector involved with the work to evaluate the

awareness and effectiveness of "stop work" practices and implementation in the

current context. 'The QC inspector referred the team to the requirements

regarding "stop work" in paragraph 4.4 of procedure P-12. "Plant Maintenance,"

Issue 5.

The QC Manager referred the team to another procedure MPRM-13

"Stop Work," Issue 2.

The team determined from review of these procedures

that they did not provide adequate guidance or the necessary authority to

enable on-site QC inspectors and supervisors to exercise "stop work" actions

when field conditions warranted. The FSV QA manager concurred with the team

that the existing procedures could not be effectively implemented and agreed

to develop a procedure to implement "stop work" and to train the FSV staff in

its implementation.

Completion of these actions is an unresolved item pending

further NRC Region IV review (267/88200-12).

2.5.3

Initiation and Disposition of Nonconformance Reports

Ncnconformance Reports (NCRs) were initiated to document nonconforming

conditions and to specify and document actions to restore conformance. The

tean reviewed the hCR file in the document room to determine any trend in the

repair of safety-related thermowells and bearing water WYE strainers.

The

,,leam determined that NCRs85-042 and 85-043 were initiated in 1985 to extract

thermocouple remnants from thermowells. NCRs87-607,88-002, and 88-003 cealt

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with the repair of bearing water WYE strainer baskets. The NCR form did not

contain provisions to evaluate and document root cause analyses and corrective

action to preclude repetition. Administrative Procedure Q-15, "Nonconformance

Reports," Issue 7, which addressed nonconformances did not require these

provisions for the resolution of NCRs. Administrative Procedure Q-16

"Corrective Action System," Issue 8, which addressed corrective action,

however, provided for these elements in the resolution of Quality Deficiency

Reports, (QDRs) Corrective Action Requests (CARS) and Corrective Action

Request Programs (CARP) but not for NCRs.

NCRs85-867, 86-608, and 85-998 which dealt with discrepancies in procurement

and installation of thermocouples were reviewed and determined to be

adequately resolved. The QA manager stated that Administrative Procedures

Q-15 and Q-16 would be revised to include provisions to document root cause

analysis and actions taken to prevent recurrence.

Completeness of these

licensee actions is an unresolved item pending further NRC Region IV review

(267/89200-13).

An elaborate computerized NCR status keeping system was in place to track and

trend future NCRs. However, key words or other similar provisions were not

established to code the NCRs prior to entry to facilitate the retrieval and

trend analysis of NCRs on the same subject.

2.5.4

Internal Audit Findings

The team reviewed a sample of QA audit reports (below) finding that the audits

were well planned, checklists were used where applicable, and adverse audit

findings were adequately documented in the form of QDRs, CARS, and CARPS.

Licensee followup and corrective actions were considered acceptable. The team

performed detailed reviews of the folicwing:

(1) Audit-QAC-87-1209 had been performed during September / October 1987 for

activities rel md to preventive maintenance (PM), training and qualifica-

tions, adequa , of maintenance procedures, and associated action to

correct previsusly identified noncompliance with regulatory requirements.

As a result of this audit, one CAR, seven QDRs and twenty improvements

items (IIs)wereinitiated. The audits and licensee corrective actions

were considered acceptable.

(2) Audit QAC-86-18E2 was performed during July through September 1986 of

activities related to independent reviews of analyses, record keeping.

clarification of surveillance intervals, an apparent reactivity anomaly,

.

validity of input data, and inconsistencies in surveillance procedures.

l

Thirteen CARS were issued for the audit findings identified during this

audit. The dispositions of CARS 148, 150, 159, 160, 161, and 167 were

reviewed during this inspection.

The licensee actions taken to correct

the conditions identified were considered acceptable.

(3) Review of Corrective Action Program (CARP-88-01) Audit Report

This audit was performed in March, 1988 to evaluate and reasses the

overall quality assurance program for corrective action. The audit

,

identified one CAR and three !!s. The CAR identified the need for

programmatic controls for the adequate resolution of externally generated

10 CFR Part 21 reports. The ils related to programmatic changes to

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improve the efficiency of the 10 CFR Part 21 revied process so that they

can be resolved in a timely manner. The audit also reviewed the actions

taken on CARP-87-02 performed in October 1987.

Review of the results of

the audit indicated that a conscientious effort was being made to resolve

items that degrade quality.

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2.5.5

Corrective Action for Operating Events

The team reviewed the licensee analyses of two operating events that occurred

on April 7 and May 6, 1988 and and the actions taken to preclude recurrence.

The team members attended one Transient Review Comittee briefing and

discussed the analyses with knowledgeable system engineers.

The results of

the review indicated that the analyses identified the probable causes of the

events and corrective action was completed in most of the cases before startup.

(1) Operating Event - Unplanned Release

On April 4,1988 with the reactor operating at approximately 74-percent

full power, a disturbance of the offsite electrical power grid actuated a

power / load urbalance (PLU) circuit which resulted 'n a turbine trip.

The

'

licensee identified that the turbine control system was unable to respond

to the upset condition because of a manufacturing deficiency in the PLU

circuit. During a July 1988 outage, the licensee plans to correct errors

in the PLU circuit.

During the cooldown, a relief valve (V6389) In the

core support floor (CSF) vent line lifted, permitting unpurified helium

to enter the reuctor plant ventilation exhaust system causing an unplanned

release of radioactive gas.

The licensee concluded that tne relief val u

setpoint was too low and reset the valve from 5 to 10 psig lift pressure.

CSF components were cleaned and the system restored to service.

In an unrelated incident, a neoprone expansion joint in one of the

circulating water lines failed and flooded both circulating water pumps.

'

The failed neoprene expansion joint was replaced with one from a

different manuf acturer and other questionable expansion joints in the

circulating water system were inspected and replaced.

(2) May 6, 1988 Transient

On May 6, 1988, the event discussed below occurred at the plant.

The

parts of the event were independent of each other. The corrective action

taken on each part of the event is also discussed.

3.

The B Circulator tripped at 12:32 pm and subsequently the A circulator

transferred to backup bearing water from normal bearing water supply.

,

All the instruments associated with the B circulator trip, including

I

level controller LC-2135 and emergency high drain valve LV-21245,

were cleaned, tested, and recalibrated where necessary.

All the

relays which would cause the transfer of the cooling water to the A

circulator from norn,al to backup bearing water, were tested and non

were observed inoperable.

b.

A reactor scram caused by two inaccurate temperature modifiers in

the reheat system occurred.

Subsequent to this transient, both

individual components including themocouples and the entire loop

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were calibrated and the loop was tested and verified to be operating

properly. The calibrations of the thermocouples is discussed in

paragraph 2.3.

c.

The radiological aspects of the transient included a purified helium

compressor trip.

The loop 2 buffer helium and bearing water systems

were contaminated by the tripping of the purified helium compressor

and the failure of the loop 2 buffer helium makeup water to transfer

to the helium supply tank because the tra7sfer switch, HS-2366, was

in the "normal" position instead of the "auto" position. The

radioactivity in the low-pressure bottles and the bulk of unplanned

release was attributed to operator error.

In his haste to reduce

the prestressed cor. crete reactor vessel (PCRV) helium inventory as

fast as reasonably achievable, an operator exceeded the capabilities

of the operating purification train.

Most of the activity went to

the the helium storage tank (LP bottles).

This area was posted as a

high radiation area and access to this area was restricted.

d.

Water that entered via circulator A became visible at 12:51 pm.

It

was postulated that water in the buffer-mid-buffer and main drain

transmitter sense lines caused the main drain control system to

erroneously raise the back pressure in the circulator bearing

cartridge and forced bearing water into the PCRV.

The licensee was

unable to determine the cause of this part of the event.

This informatien indicated that the licensee determined three of the four

causes of this transient and took adequate corrective actions.

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3.0 DP. AFT INFORMATION RELEASED to the LICENSEE

During this inspection, one of the team members gave a member of the

licer.see's staff a copy of some handwritten observations. Attachment B is a

copy of the document that was released to the licensee.

.

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, . . *

4.0 EXIT MEETING

The operational safety team and other NRC representatives met with licensee

,

'

personnel on May 20, 1988 to discuss the scope and findings of the inspection.

Attendees at the exit meeting are identified in Attachment A.

During the

inspection, the team also contacted other members of the licensee's staff not

identified in Attachment A to discuss issues and ongoing activities.

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ATTACHMENT A

ATTENDANCE SHEET

EXIT MEETING - May 20, 1988

NAME

ORGANIZATION

POSITION TITLE

J. E. Cummins

USNRC

OSTI Team Leader

E. V. Imbro

USNRC

OSTI Assistant Team Leader

C. J. Haughney

USNRC

Chief. Special Inspection Branch, NRR

J. D. Smith

USNRC

Operations Engineer

D. R. Hunter

USNRC-RIV

Senior Reactor Inspector

D. A. Beckman

USNRC

Consultant

D. B. Waters

USNRC

Consultant

J. M. Sharkey

USNRC

Operations Engineer (Mechanical)

K. Naidu

USNRC

Reactor Inspector

T. F. Westerman

USNRC-RIV

Chief, Projects Section B

P. F. Tomlinson

PSC

Manager, QA

J. Eggebroten

"C

Technical Projects Manager

_

M. H. Holmes

PSC

Nuclear Licensing Manager

D. Goss

PSC

Nuclear Regulatory Affairs Manager

P. Michavo

USNRC

Resident Inspector

L. J. Callan

USNRC

Director, Div. of Reactor Proj., RIV

H. O'Hagan

PSC

Outage Manager

R. Crown

PSC

Nuclear Engineering Manager

K. L. Heitner

USNRC

NRR Project Manager

M. E. Deniston

PSC

Shift Supervisor - Audit Coordinator

R. W. Williams, Jr.

PSC

V.P. Nuclear Operations

'

C. H. Fuller

PSC

Manager, Nuclear Production

M. Coppello

PSC

Central Planning & Sched. Manager

L. D. Scott

PSC

OA Services Manager

M. J. Ferris

PSC

QA Operations Manager

F. J. Borst

PSC

Nuclear Training Manager

N. Snyder

PSC

Maintenance Department Manager

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H. L. Brey

PSC

Mgr., Nuclear Licen. & Resource Mgmt.

M. Block

PSC

Manager, System Engineering

D. W. Evans

PSC

Operations Manager

F. J. Novachek

PSC

Nuclear Support Manager

D. Rodgers

PSC

Nuclear Computer Service Manager

S. Piepenbrink

PSC

Management QC Supervisor

M. Leht

PSC

OA Engineering Supervisor

R. Sargent

PSC

Asst. to V.P. Nuclear Operations

A. L. Kitzman

PSC

Nuclear Documents Supervisor

D. L. Weber

PSC

Asst. to Station Manager

J. Gramling

PSC

Supervisor, Nuclear Licensing - Ops.

W. M. Dender, Jr.

PSC

Nuclear Licensing, Coordinator

L. W. Cogdill

PSC

Planner

R. W. Moler

PSC

Scheduling Engineer

D. Warrenbourg

PSC

Manager Nuclear Engineering

A-1

_ _ _ _ _ _ _ _ _ _ _ _ _

AT.TACHMENT B

Pg 1 of 2

.

COPY OF INFORMATION RELEASED TO LICENSEE

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AMAChMEt.T B

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, COPY OF INFORMAT10tl RELEASED TO LICENSEE

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ATTACHMENT C

j

ABBREVIATIONS AND ACRONYMS

,

ACM

alternate cooling method

ANSI

American National Standards Institute

AEOD

Analysis and Evaluation of Operational Data

,

ASME

American Society of Mechanical Engineers

CAR

corrective action request

CWP

controlled work procedure

,

DRT

discrepant report tag

'

EFW

emergency feedwater

EP

emergency procedure

FSAR

final safety analysis report

FSV

Fort St. Vrain

HTGR

high temperature gas-cooled reactor

IAC

instrumentation and controls

IEN

inspection and enforcement notice

INP0

Institute of Nuclear Power Operations

IST

inservice test

IV

independent verification

LCO

limiting condition for operation

LWR

light water reactors

MAP

maintenance administrative procedure

M&TE

measuring and test equipment

NCR

nonconformance report

NFSC

nuclear facility safety comittee

dRI

nonsafety-related item

ISSS

nuclear steam supply system

0ER

operating experience report

'

DIAG

operating information assessment group

PCRV

prestressed concrete reactor vessel

PDR

procedure oeviation report

PM

preventive maintenance

.

PORC

plant operations review comittee

3

PSC

Public Service of Colorado

i

QA

quality assurance

QAD

quality assurance department

QC

quality control

SALP

systematic assessment of licensees perfonnance

SER

safety evaluation report

>

SOAP

station operators administrative procedure

SOER

standard operating expetence report

I

S0P

standard operating procedure

!

SR

surveillance procedure requirement

!

SSR

station service request

SVL

system valve list

TCR

temporary configuration report

TS

technical specifications

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